Dear readers, it is with high spirits I am posting my first NrgBuzz ever (and certainly not the last).
My name is Raffik Lazar, I am the founder, managing director and Lead Geologist for GeomodL.
GeomodL is a subsurface consultancy firm specialized in reservoir modelling and carbonates reservoirs. I created GeomodL in 2016 after having spent 10 years with Shell as geologist across 3 continents.
GeomodL is the result of my passion for geomodelling and my entrepreneur spirit.
Today's NrgBuzz will be dealing with subsurface integration.
Subsurface integration has always been a hot topic for the EP companies. Today, more than ever, there is a strong push to tackle the subsurface challenges in an integrated fashion. Unfortunately, the misconception of collocating subsurface people in the same corridor as the one and only requirement to achieve subsurface integration is well alive.
Subsurface integration, put in simple words, is looking at the subsurface object from different angles (the subsurface disciplines) to ensure no stones are left unturned. The key is to find answers and remove as many question marks as possible on the understanding of the reservoir. Taking the example of a classical reservoir modelling exercise (from inputs to forecast), four levels of subsurface integration can be distinguished:
Level 0: Disintegration (no integration)
The reservoir model is built upon subtasks that are done in isolation and not contemporary each other’s. A good example would be a legacy seismic interpretation performed several years prior to the petrophysical interpretation. The conceptual ideas used for the static model takes all those inputs and simply “plug” them in the geomodelling software without further attempt to decipher the subsurface and identify trends.
Level 1: Proto integration
The infamous “throw over the fence” culture. All the subsurface building blocks are put in place sequentially, QC’ed and handed over to the next link in the chain. The textbook example is the seismic and the petrophysical interpretation performed concurrently. The resulting inputs are approved by the technical authorities and handed over to the Geomodeller. Once the static model is built, it is handed over to the reservoir engineer for history match / forecasting purpose. Often at that stage, significant changes are required to reconstruct a dynamic signal matching the production data. There is no turn back in the sequence and the reservoir engineer is left alone to get the match. I have personally observed some instances where permeability multiplication by several folds and porosity increase by 5 p.u., in total contradiction with the data, were necessary to approach near a history match state.
Level 2: Pseudo integration
The system in place allows some feedbacks to be recycled. Physical collocation between the different subsurface people facilitates communication. A major flaw remains as the work is still done sequentially. If a potential cause of mismatch is identified, another iteration occurs and a new “product” is generated. Although the flexibility is commendable, there is no guarantee of improvement. Worst, this can stretch the overall project timeline and cost valuable extra man hours for potentially no added value.
At this stage, from level 0 to level 3, the reservoir modelling exercise is a sum of several “sub projects”
Level 3: True integration
From the initial set up, the team is fully aligned on the final objective. Collocation is not just physical but also digital. Every discipline has access to one consolidated database. Integrated sessions become a meaningful medium of exchange where all the different disciplines are constantly looking beyond their borders. All the sub tasks start at the same time. Very early in the workflow, a first pass static model is handed over to the reservoir engineer to establish the simulation workflow and distillate the first critical understandings of the reservoir. Seismic close the loop and petrophysical log QC are performed early in the game and in consultation with the full team. Once the inputs are generated, the Petrophysicist and the Seismic Interpreter stay engaged and contribute to subsurface discussions until the simulation stage. That way, some important aspects such as fault seal or reservoir capillary effect on saturation stay high on the radar and can be debated.
Current state and way forward
While it is easy to out pass level 0, most of the EP companies are often stuck between level 1 (proto integration) and level 2 (pseudo integration).
Having a subsurface team with high interpersonal / technical skills is a sine qua non for achieving true subsurface integration. Corporate culture must encourage and cement the bond between the team members.
Computing capabilities and subsurface software must enable flexibility at the click of a mouse.
Most importantly, workflows, modelling philosophy and paradigm should be challenged to ensure that true subsurface integration transitions from being a mere ambition to a (new?) reality.
If you / your organization would like some advices to achieve true subsurface integration. Get in touch with me at [email protected], I would be more than happy to share my experience.
Enjoyed reading this article? Please hit like / share and drop me a comment to tell me what you think about subsurface integration.
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Source: U.S. Energy Information Administration, based on Bloomberg L.P. data
Note: All prices except West Texas Intermediate (Cushing) are spot prices.
The New York Mercantile Exchange (NYMEX) front-month futures contract for West Texas Intermediate (WTI), the most heavily used crude oil price benchmark in North America, saw its largest and swiftest decline ever on April 20, 2020, dropping as low as -$40.32 per barrel (b) during intraday trading before closing at -$37.63/b. Prices have since recovered, and even though the market event proved short-lived, the incident is useful for highlighting the interconnectedness of the wider North American crude oil market.
Changes in the NYMEX WTI price can affect other price markers across North America because of physical market linkages such as pipelines—as with the WTI Midland price—or because a specific price is based on a formula—as with the Maya crude oil price. This interconnectedness led other North American crude oil spot price markers to also fall below zero on April 20, including WTI Midland, Mars, West Texas Sour (WTS), and Bakken Clearbrook. However, the usefulness of the NYMEX WTI to crude oil market participants as a reference price is limited by several factors.
Source: U.S. Energy Information Administration
First, NYMEX WTI is geographically specific because it is physically redeemed (or settled) at storage facilities located in Cushing, Oklahoma, and so it is influenced by events that may not reflect the wider market. The April 20 WTI price decline was driven in part by a local deficit of uncommitted crude oil storage capacity in Cushing. Similarly, while the price of the Bakken Guernsey marker declined to -$38.63/b, the price of Louisiana Light Sweet—a chemically comparable crude oil—decreased to $13.37/b.
Second, NYMEX WTI is chemically specific, meaning to be graded as WTI by NYMEX, a crude oil must fall within the acceptable ranges of 12 different physical characteristics such as density, sulfur content, acidity, and purity. NYMEX WTI can therefore be unsuitable as a price for crude oils with characteristics outside these specific ranges.
Finally, NYMEX WTI is time specific. As a futures contract, the price of a NYMEX WTI contract is the price to deliver 1,000 barrels of crude oil within a specific month in the future (typically at least 10 days). The last day of trading for the May 2020 contract, for instance, was April 21, with physical delivery occurring between May 1 and May 31. Some market participants, however, may prefer more immediate delivery than a NYMEX WTI futures contract provides. Consequently, these market participants will instead turn to shorter-term spot price alternatives.
Taken together, these attributes help to explain the variety of prices used in the North American crude oil market. These markers price most of the crude oils commonly used by U.S. buyers and cover a wide geographic area.
Principal contributor: Jesse Barnett
A month ago, the world witnessed something never thought possible – negative oil prices. A perfect storm of events – the Covid-19 lockdowns, the resulting effect on demand, an ongoing oil supply glut, a worrying shortage of storage space and (crucially) the expiry of the NYMEX WTI benchmark contract for May, resulted in US crude oil prices falling as low as -US$37/b. Dragging other North American crude markers like Louisiana Light and Western Canadian Select along with it, the unique situation meant that crude sellers were paying buyers to take the crude off their hands before the May contract expired, or risk being stuck with crude and nowhere to store it. This was seen as an emblem of the dire circumstances the oil industry was in, and although prices did recover to a more normal US$10-15/b level after the benchmark contract switched over to June, there was immense worry that the situation would repeat itself.
Thankfully, it has not.
On May 19, trade in the NYMEX WTI contract for June delivery was retired and ticked over into a new benchmark for July delivery. Instead of a repeat of the meltdown, the WTI contract rose by US$1.53 to reach US$33.49/b, closing the gap with Brent that traded at US$35.75b. In the space of a month, US crude prices essentially swung up by US$70/b. What happened?
The first reason is that the market has learnt its lesson. The meltdown in April came because of an overleveraged market tempted by low crude oil prices in hope of selling those cargoes on later at a profit. That sort of strategic trading works fine in a normal situation, but against an abnormal situation of rapidly-shrinking storage space saw contract holders hold out until the last minute then frantically dumping their contracts to avoid having to take physical delivery. Bruised by this – and probably embarrassed as well – it seems the market has taken precautions to avoid a recurrence. Settling contracts early was one mechanism. Funds and institutions have also reduced their positions, diminishing the amount of contracts that need to be settled. The structural bottleneck that precipitated the crash was largely eliminated.
The second is that the US oil complex has adjusted itself quickly. Some 2 mmb/d of crude production has been (temporarily) idled, reducing supply. The gradual removal of lockdowns in some US states, despite medical advisories, has also recovered some demand. This week, crude draws in Cushing, Oklahoma rose for the second consecutive week, reaching a record figure of 5.6 million barrels. That increase in demand and the parallel easing of constrained storage space meant that last month’s panic was not repeated. The situation is also similar worldwide. With China now almost at full capacity again and lockdowns gradually removed in other parts of the world, the global crude marker Brent also rose to a 2-month high. The new OPEC+ supply deal seems to be working, especially with Saudi Arabia making an additional voluntary cut of 1 mmb/d. The oil world is now moving rapidly towards a new normal.
How long will this last? Assuming that the Covid-19 pandemic is contained by Q3 2020, then oil prices could conceivably return to their previous support level of US$50/b. That is a big assumption, however. The Covid-19 situation is still fragile, with major risks of additional waves. In China and South Korea, where the pandemic had largely been contained, recent detection of isolated new clusters prompted strict localised lockdowns. There is also worry that the US is jumping the gun in easing restrictions. In Russia and Brazil – countries where the advice to enforce strict lockdowns was ignored as early warning signs crept in – the number of cases and deaths is still rising rapidly. Brazil is a particular worry, as President Jair Bolosnaro is a Covid-19 skeptic and is still encouraging normal behaviour in spite of the accelerating health crisis there. On the flip side, crude output may not respond to the increase in demand as easily, as many clusters of Covid-19 outbreaks have been detected in key crude producing facilities worldwide. Despite this, some US shale producers have already restarted their rigs, spurred on by a need to service their high levels of debt. US pipeline giant Energy Transfer LP has already reported that many drillers in the Permian have resumed production, citing prices in the high-US$20/b level as sufficient to cover its costs.
The recovery is ongoing. But what is likely to happen is an erratic recovery, with intermittent bouts of mini-booms and mini-busts. Consultancy IHS Markit Energy Advisory envisions a choppy recovery with ‘stop-and-go rallies’ over 2020 – particularly in the winter flu season – heading towards a normalisation only in 2021. It predicts that the market will only recover to pre-Covid 19 levels in the second half of 2021, and a smooth path towards that only after a vaccine is developed and made available, which will be late 2020 at the earliest. The oil market has moved from certain doom to cautious optimism in the space of a month. But it will take far longer for the entire industry to regain its verve without any caveats.
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