January 30, 2019 - Nom Geo
Reservoir to Bowser 1
January 30th 2019
The looming Brexit, and the record US government shutdown may be weighing on global markets which have been lacklustre over January.
Brent oil has been level at $61 per barrel and West Texas Intermediate (WTI) at $52 per barrel. Both are around $8 per barrel higher than the lowest levels experienced last quarter and represent a rapid recovery to more attractive levels.
Critically, oil companies still see prices of $60 per barrel and $50 per barrel respectively as positive investment cases, meaning that land based and also deepwater developments will go ahead.
With most commentators shouting from the rooftops that Permian shale development is slowing down, it is worthwhile remembering that production is still growing, and that 2019 drilling programmes are yet to kick in. A slowdown in growth was always expected because of the accelerated startup of newly completed wells from around September when most of 2018’s completions were in final stages of coming on stream.
The production cuts in Alberta Canada may be helping to push up the price of Western Canadian Select (WCS). It rose from the third quarter freefall level of $12 per barrel (on a netback basis) to $44.46 by January 29, just $9 per barrel lower than WTI. The case for Canadian heavy crude pricing is expected to be buoyed in the short term as sanctions against Venezuela reduce further the supply of heavy.
In January, US natural gas prices dropped back to less than $3/MMBtu in a range seen over most of H1 2018. Overall the market for natural gas reflects a stable supply and ample storage, with none of the usual winter volatility normally seen in Spain, the UK and China, and prices remain firmly lower than last year’s winter.
Refining margins in the United States are represented by 3-2-1 crack-spreads against WTI of $9.30 per barrel on January 30. Gasoline and diesel futures imply an upwardly trending price for both fuels in February, but the issue is not simple with gasoline stockpiles at record highs East of the Rockies, and at lower than average levels to the West.
In breaking news, China National Offshore Oil Corporation (CNOOC) along with partners have just announced a 250 million barrel-oil-equivalent (boe) oil discovery at Glengorm, the largest in a decade for the UK since the discovery of Culzean 11 years ago. The exploration well, drilled to a depth of 16,000ft (4875m), has intersected a gas-condensate reservoir, with the location of the P2215 licence suggesting that a subsea tie-back development between the field and the Culzean, Elgin-Franklin platforms is a possible development pathway. Culzean is set to shortly come on-stream.
Already at around twenty times the size of the Glengorm discovery, ExxonMobil is hoping to extend its run of discoveries in deepwater Guyana. The drilling of Haimara-1 well in the Starbroek block began early this month and total discoveries now represent around 5.1b barrels of oil and gas. The previous ten discoveries are in sandstone reservoirs similar to the targeted formation at Haimara. This is typical geology found on both sides of the Atlantic rim. Geologically at least, Guyana has potential to equal Angola’s large oil sector development.
On the Pacific side of South America, in Colombia, India’s ONGC flowed 4kbopd of light oil at Indico-1 well from a 9833ft (3,000m) deep sandstone reservoir. But with wellhead pressure of just 241psi and no gas, the sandstone reservoir will likely be developed as a high density well field, a relatively high cost proposition. The discovery was preceded by the Mariposa 1 well in 2017.
In Southern Mexico, Talos Energy has successfully intersected a 177m thick gross oil bearing sandstone reservoir at Zama-2, the first of three appraisal wells. Appraisal wells are drilled to test flow conditions and to assess commerciality of discoveries. The size of the oil section at Zama-2 is considerably larger than the Zama-1 discovery well and is good news for the Talos, Sierra and Premier Oil partnership.
South American and also African sandstone reservoirs on the Atlantic rim are mostly Cretaceous (145-66ma) in age and sediments correspond with the splitting of the South American and African plates.
Typically, the rocks are highly permeable, meaning that reservoirs enjoy sustained pressure from surrounding aquifers and overlying gas caps. The high permeability also allows each well to access oil from a large drainage area, reducing the number of wells required for a full-field development.
Most offshore oil discoveries in this type of geology are well preserved in the sub-surface environment and contain high gas content, which in turn means that reservoir pressures are high. The geology also responds well to water injection, as a flow-assurance measure.
Risks include compaction, or a partial collapse of pore spaces as pressure is drawn down. As well, there exists high risk of sand-grains entering into production tubing, resulting in wear and damage to equipment. Most wells are therefore completed with some barrier to sand entry such as screening or small perforation size, while water injection sustains hydrostatic pressure, limiting compaction.
Other risks are early water breakthrough, meaning there is potential for formation water to bypass oil zones, reducing the economic life of wells through lower oil recovery.
Mid-Stream (pipelines, processing and shipping)
Gas Pipelines from the Permian Basin to the Gulf Coast will greatly expand gas supply to Gulf LNG projects, according to NextDecade’s CEO Matthew Schatzman, who is promoting the 27 million tonne per annum capacity Rio Grande LNG project in Brownsville, Texas.
NextDecade’s Rio Bravo Pipeline (RBPL) project is comprised of twin 42-inch pipelines that share rights of way along a 137.5-mile route from the Agua Dulce area to Brownsville, Texas. The project includes three 180,000-horsepower compressor stations, six mainline valve sites with two valves per location (one for each pipeline), four metering sites housing a total of six meter stations, and other ancillary facilities.
The new Permian basin supplies will come from expected new pipelines connecting Waha in western Texas to the Agua Dulce Hub. This will be good news for shale producers after Waha-hub natural gas price last November fell to $0/MMBtu due to insufficient take-away capacity.
Crude transport from Canada is also up, but long term pipeline construction is still being throttled by court orders against new projects. CN Rail reported a 50% increase in revenues from the transport of petroleum and chemicals, rising to $815 million in the fourth quarter 2018. Crude oil shipments rose to 232,000 bbl/day in Q4 and 133,000 barrels per day for the full year 2018.
Alberta is landlocked, and crude either travels to refineries in Edmonton, to US refineries as far as the Gulf Coast, or to Pacific markets via pipelines into British Columbia. Transport is by both rail and pipeline. Currently pipeline projects are stalled as environmental and First Nations groups oppose developments.
ExxonMobil is moving ahead with construction of a 250,000 barrel per day (kbpd) atmospheric crude distillation unit (CDU), lifting the total of its Baytown Texas refinery from 366kbpd up to 616kbpd. The expansion is due to increased future production from the Permian Basin shale. If follows announcements in 2018 of a new 1.5 million ton-per-year ethane cracker at the company’s integrated Baytown chemical and refining complex in Texas.
ExxonMobil and SABIC have also created a new joint venture to advance development of the Gulf Coast Growth Ventures project, a 1.8 million metric ton ethane cracker currently planned for construction in San Patricio County, Texas. Along with gasoline and diesel, Baytown also includes plants that produce chemicals and lubricants.
In the United Arab Emirates (UAE) Italian oil major Eni and Austria’s OMV are to each acquire from ADNOC (Abu Dhabi National Oil Company) a 20% and 15% respectively equity interests in ADNOC’s 922kbpd refining business. ADNOC currently operates the giant Ruwais East and West complexes and the Abu Dhabi refinery. Both were subject to recently completed clean-fuels projects.
The cash value of each deal is respectively $3.3 billion and $2.5 billion. The attraction is ADNOC’s low refining costs which is expected to bring Eni’s company-wide average margin target down to around $1.50 per barrel. For OMV, the acquisition allows t to participate in netback optimized export sales and international trading activities.
Along with operating cost advantages, it allows both companies immediate expanded capacity for meeting their own downstream fuels and lubricant markets.
Finally, China’s gasoline exports rose in December to a seven month high of 1.3 million tonnes (mt), more than twice November’s 633mt. China is trying to incentivise its refineries to operate at higher rates and has lifted export quotas by 3% to 14.15mt for 2019.
If you like to receive automatic emails please subscribe using the box below.