Raffik Lazar

Founder, Managing Director and Lead Geologist at GeomodL
Last Updated: May 5, 2017
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Petroleum Geoscience
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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)

uploads1493951010283-level0.png

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

uploads1493951026162-level1.png

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

uploads1493951041352-level2.png

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

uploads1493951064203-level3.png

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.

Geomodelly yours!

Subsurface Integration Geomodelling
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Your Weekly Update: 20 -24 May 2019

Market Watch

Headline crude prices for the week beginning 20 May 2019 – Brent: US$73/b; WTI: US$63/b

  • As the OPEC+ group signals its intentions to continue its supply deal through to the end of 2019 and US President Donald Trump increases pressure on Iran, crude prices have kept their strength
  • The OPEC+ group met in Jeddah last weekend to lay the groundwork for the upcoming OPEC meeting in Vienna on June 25, with Saudi Arabia and Russia committing to keep oil supplies constrained over the rest of the year but avoiding any ‘genuine shortage’
  • There appears to be some reticence on the part of Russia to sign up to extending the supply deal, with Energy Minister Alexander Novak recently dropping hints about relaxing curbs and the country barely fulfilling its current pledge
  • But more worrisome than Russian reluctance is the issue of Iran; the risk of full-blown military conflict has escalated with America offering barbed words after attacks on a key Saudi pipeline spooked the market while the UAE said it is committed to ‘de-escalation’ after attacks on ships in the Persian Gulf
  • While these geopolitical issues have been driving prices up, the ever-present issue of surging American production remains – with US shale set oil for a 16% growth in 2019, and 470 million barrels of US crude finding home in 38 countries over the six-month period between October 2018 and March 2019, up from 359 million barrels across 31 countries in the previous period
  • While US crude production continues to rise, the active US rig count continues to moderate; three oil rigs were dropped and two gas rigs were gained in the last week, leading to a net decline of one rig – the third consecutive week of losses
  • OPEC+’s definitive statement on their strategy for the remainder of 2019 will calm the markets, but the boiling US-China trade conflict now threatens global growth, as the US fired a major salvo by introducing harsh restrictions on Chinese telecommunication giant Huawei; crude prices will trend downwards, with Brent at US$68-70/b and WTI at US$59-61/b


Headlines of the week

Upstream

  • Eni has struck oil at Block 15/06 offshore Angola in the Ndungu exploration prospect, estimated to contain up to 250 million barrels of light oil in place
  • Norway’s Equinor has exercised preferential rights to acquire an additional 22.45% in the Caesar Tonga oil field in the US Gulf of Mexico from Shell for US$965 million, increasing its stake in the field to 46%
  • The main cross-country pipeline network in Saudi Arabia, which connects the Persian Gulf and the Red Sea, has been restarted after a drone attack on two pumping stations by Iranian-backed rebels halted operations for a week
  • Uganda has launched its second licensing round, with the Avivi, Omuka, Kasuruban, Turaco and Ngaji blocks in the oil-rich Albertine Graben on offer
  • Kuwait’s Kufpec has signed a deal to explore and potentially develop the onshore Block 3371-19 in Pakistan
  • Eni has begun drilling and exploration activities at Block 114 in the Song Hong basin offshore central Vietnam
  • Eni and Total picked up a joint 4 offshore blocks at Cote d’Ivoire’s latest block sale, with the state aiming to generate US$275 million from the sale

Midstream & Downstream

  • China has issued a second batch of fuel export quotas for 2019 that was 30% higher than the first batch in January, allowing 23.79 million tons of products to be shipped overseas just as Hengli’s 400 kb/d Dalian refinery starts up
  • The UAE’s Brooge Petroleum and Gas Investment Co has announced plans for a 250 kb/d refinery in Fujairah to produce clean IMO-compliant bunker fuels
  • The fallout from tainted Russian crude exports through the Druzhba pipeline and Ust-Luga port continues as Russia admits that clean-up will take longer than expected, as Kazakhstan seeks damages for its tainted crude and Total halts operations at its 230 kb/d Leuna refinery in Germany over contamination
  • Sinopec’s 200 kb/d Qingdao refinery is set to shut down for an extended period for a planned major overhaul to upgrade fuel quality
  • PDVSA’s 310 kb/d Cardon refinery in Venezuela has been shut down due to damages at some units, exacerbating the country’s ongoing fuel crisis

Natural Gas/LNG

  • Santos has struck a deal to acquire a 14.3% stake in the PRL3 licence in Papua New Guinea, which includes the 4.4 tcf P’nyang natural gas field, which will underpin the planned expansion of PNG LNG with the a new 2.7 mtpa train
  • First LNG has been produced at the Cameron LNG project in Louisiana as Train 1 begins output, the first of three 4.5 mtpa trains to start up in Phase 1
  • The US state of New York has denied a permit for the US$1 billion Williams Co shale gas pipeline, scuppering plans to deliver shale gas from Pennsylvania, Ohio and West Virginia to New York City and the US Northeast
  • Saudi Aramco’s march into the LNG space continues as it is set to take a ‘sizeable’ stake in Sempra Energy’s proposed Port Arthur LNG export project
  • Petronas’ PFLNG Satu has started first LNG production within three days of being relocated to the Kebabangan Cluster gas field offshore Sabah
  • Freeport LNG has now received federal approval to add a fourth train to its Texas LNG export terminal, bringing total capacity to over 20 mtpa
May, 24 2019
The Battle for Anadarko

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:

  • US$38 billion cash-and-stock
  • Oxy will received a US$10 billion injection from Berkshire Hathaway
  • Oxy will sell US$8.8 billion of assets in Africa to Total
  • Chevron receives a US$1 billion break-up fee
May, 23 2019
Venezuelan crude oil production falls to lowest level since January 2003

monthly venezueal crude oil production

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.

monthly venezuela crude oil rig count

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.

monthly venezuela crude oil exports by destinatoin

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.

May, 21 2019