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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Headline crude prices for the week beginning 20 May 2019 – Brent: US$73/b; WTI: US$63/b
Headlines of the week
Midstream & Downstream
At first, it seemed like a done deal. Chevron made a US$33 billion offer to take over US-based upstream independent Anadarko Petroleum. It was a 39% premium to Anadarko’s last traded price at the time and would have been the largest industry deal since Shell’s US$61 billion takeover of the BG Group in 2015. The deal would have given Chevron significant and synergistic acreage in the Permian Basin along with new potential in US midstream, as well as Anadarko’s high potential projects in Africa. Then Occidental Petroleum swooped in at the eleventh hour, making the delicious new bid and pulling the carpet out from under Chevron.
We can thank Warren Buffet for this. Occidental Petroleum, or Oxy, had previously made several quiet approaches to purchase Anadarko. These were rebuffed in favour of Chevron’s. Then Oxy’s CEO Vicki Hollub took the company jet to meet with Buffet. Playing to his reported desire to buy into shale, Hollub returned with a US$10 billion cash infusion from Buffet’s Berkshire Hathaway – which was contingent on Oxy’s successful purchase of Anadarko. Hollub also secured a US$8.8 billion commitment from France’s Total to sell off Anadarko’s African assets. With these aces, she then re-approached Anadarko with a new deal – for US$38 billion.
This could have sparked off a price war. After all, the Chevron-Anadarko deal made a lot of sense – securing premium spots in the prolific Permian, creating a 120 sq.km corridor in the sweet spot of the shale basin, the Delaware. But the risk-adverse appetite of Chevron’s CEO Michael Wirth returned, and Chevron declined to increase its offer. By bowing out of the bid, Wirth said ‘Cost and capital discipline always matters…. winning in any environment doesn’t mean winning at any cost… for the sake for doing a deal.” Chevron walks away with a termination fee of US$1 billion and the scuppered dreams of matching ExxonMobil in size.
And so Oxy was victorious, capping off a two-year pursuit by Hollub for Anadarko – which only went public after the Chevron bid. This new ‘global energy leader’ has a combined 1.3 mmb/d boe production, but instead of leveraging Anadarko’s more international spread of operations, Oxy is looking for a future that is significantly more domestic.
The Oxy-Anadarko marriage will make Occidental the undisputed top producer in the Permian Basin, the hottest of all current oil and gas hotspots. Oxy was once a more international player, under former CEO Armand Hammer, who took Occidental to Libya, Peru, Venezuela, Bolivia, the Congo and other developing markets. A downturn in the 1990s led to a refocusing of operations on the US, with Oxy being one of the first companies to research extracting shale oil. And so, as the deal was done, Anadarko’s promising projects in Africa – Area 1 and the Mozambique LNG project, as well as interest in Ghana, Algeria and South Africa – go to Total, which has plenty of synergies to exploit. The retreat back to the US makes sense; Anadarko’s 600,000 acres in the Permian are reportedly the most ‘potentially profitable’ and it also has a major presence in Gulf of Mexico deepwater. Occidental has already identified 10,000 drilling locations in Anadarko areas that are near existing Oxy operations.
While Chevron licks its wounds, it can comfort itself with the fact that it is still the largest current supermajor presence in the Permian, with output there surging 70% in 2018 y-o-y. There could be other targets for acquisitions – Pioneer Natural Resources, Concho Resources or Diamondback Energy – but Chevron’s hunger for takeover seems to have diminished. And with it, the promises of an M&A bonanza in the Permian over 2019.
The Occidental-Anadarko deal:
Source: U.S. Energy Information Administration, Short-Term Energy Outlook
In April 2019, Venezuela's crude oil production averaged 830,000 barrels per day (b/d), down from 1.2 million b/d at the beginning of the year, according to EIA’s May 2019 Short-Term Energy Outlook. This average is the lowest level since January 2003, when a nationwide strike and civil unrest largely brought the operations of Venezuela's state oil company, Petróleos de Venezuela, S.A. (PdVSA), to a halt. Widespread power outages, mismanagement of the country's oil industry, and U.S. sanctions directed at Venezuela's energy sector and PdVSA have all contributed to the recent declines.
Source: U.S. Energy Information Administration, based on Baker Hughes
Venezuela’s oil production has decreased significantly over the last three years. Production declines accelerated in 2018, decreasing by an average of 33,000 b/d each month in 2018, and the rate of decline increased to an average of over 135,000 b/d per month in the first quarter of 2019. The number of active oil rigs—an indicator of future oil production—also fell from nearly 70 rigs in the first quarter of 2016 to 24 rigs in the first quarter of 2019. The declines in Venezuelan crude oil production will have limited effects on the United States, as U.S. imports of Venezuelan crude oil have decreased over the last several years. EIA estimates that U.S. crude oil imports from Venezuela in 2018 averaged 505,000 b/d and were the lowest since 1989.
EIA expects Venezuela's crude oil production to continue decreasing in 2019, and declines may accelerate as sanctions-related deadlines pass. These deadlines include provisions that third-party entities using the U.S. financial system stop transactions with PdVSA by April 28 and that U.S. companies, including oil service companies, involved in the oil sector must cease operations in Venezuela by July 27. Venezuela's chronic shortage of workers across the industry and the departure of U.S. oilfield service companies, among other factors, will contribute to a further decrease in production.
Additionally, U.S. sanctions, as outlined in the January 25, 2019 Executive Order 13857, immediately banned U.S. exports of petroleum products—including unfinished oils that are blended with Venezuela's heavy crude oil for processing—to Venezuela. The Executive Order also required payments for PdVSA-owned petroleum and petroleum products to be placed into an escrow account inaccessible by the company. Preliminary weekly estimates indicate a significant decline in U.S. crude oil imports from Venezuela in February and March, as without direct access to cash payments, PdVSA had little reason to export crude oil to the United States.
India, China, and some European countries continued to receive Venezuela's crude oil, according to data published by ClipperData Inc. Venezuela is likely keeping some crude oil cargoes intended for exports in floating storageuntil it finds buyers for the cargoes.
Source: U.S. Energy Information Administration, Short-Term Energy Outlook, and Clipper Data Inc.
A series of ongoing nationwide power outages in Venezuela that began on March 7 cut electricity to the country's oil-producing areas, likely damaging the reservoirs and associated infrastructure. In the Orinoco Oil Belt area, Venezuela produces extra-heavy crude oil that requires dilution with condensate or other light oils before the oil is sent by pipeline to domestic refineries or export terminals. Venezuela’s upgraders, complex processing units that upgrade the extra-heavy crude oil to help facilitate transport, were shut down in March during the power outages.
If Venezuelan crude or upgraded oil cannot flow as a result of a lack of power to the pumping infrastructure, heavier molecules sink and form a tar-like layer in the pipelines that can hinder the flow from resuming even after the power outages are resolved. However, according to tanker tracking data, Venezuela's main export terminal at Puerto José was apparently able to load crude oil onto vessels between power outages, possibly indicating that the loaded crude oil was taken from onshore storage. For this reason, EIA estimates that Venezuela's production fell at a faster rate than its exports.
EIA forecasts that Venezuela's crude oil production will continue to fall through at least the end of 2020, reflecting further declines in crude oil production capacity. Although EIA does not publish forecasts for individual OPEC countries, it does publish total OPEC crude oil and other liquids production. Further disruptions to Venezuela's production beyond what EIA currently assumes would change this forecast.