9th August 2019
Oil Drilling Activity
Onshore US drilling activity dropped 9 with a total active count of 909 rigs; those targeting oil down 6, with the total at 764. Across the three major unconventional oil basins, the oil-rig count was up, with Permian up 2, Williston and Eagle Ford flat.
US domestic crude output increased by 100,000 barrels per day, recovering from an earlier GOM storm; crude oil production now stands at 12.3 million barrels per day, just under its weekly record high at 12.4 million hit in May. This week’s domestic crude oil production estimate incorporates a re-benchmarking that lowered estimated volumes by 133,000 barrels per day.
Crude oil stockpiles rose last week after nearly two months of declines as net imports jumped to their highest since January. Inventories rose 2.4 million barrels compared with expectations for a decrease of 2.8 million barrels.
Carbon Management – Gorgon, a not so mythical creature that captures carbon
Gorgon is a Greek mythical creature, comprising three sisters who had hair made of living snakes and whose stare turned their enemies immediately to stone, that I remember seeing in movies as a child. Whilst last week’s Monitor on using captured CO2 to produce novel cements could also have been relevant to this title, I am actually referring to the start-up this week of the Gorgon LNG Carbon Capture and Storage (CCS) project.
The Gorgon liquefied natural gas (LNG) development operated by Chevron has been a massive $54 Billion undertaking, and a marvel of engineering, over several decades since the field was first discovered. I have had the pleasure to work on both production flow assurance issues for the project in the 1990s and then on the planning for the CO2 storage project in the 2000s. The reason for my first experience was that long subsea pipelines are needed to transport the produced fluids from the offshore fields, creating risks with hydrate blockages. The second reason is that produced natural gas from the fields contains about 14% CO2 as the result of natural processes over geological timescales; however, removal is required prior to the gas entering the liquefaction process to prevent the CO2 from freezing and causing operational and safety issues. Rather than vent the separated CO2, as is the case with some other natural gas projects, the partnership proposed that it would undertake a CO2 storage solution to receive approval from the regulator. It therefore undertook a comprehensive plan to characterize a suitable deep saline formation 2km under Barrow Island, located 50km off the Western Coast of Australia, itself an environmentally protected location where the liquefaction plant was to be located.
While natural gas production started in 2017, the start of CO2 injection was delayed unexpectedly. So what happened? It has been reported by others that excess water had entered the CO2 injection pipeline during initial commissioning and, given the corrosive nature of this forming carbonic acid with CO2, it needed to be removed, pipework and valves inspected, modifications implemented and operational procedures adapted to prevent reoccurrence. With this now completed, the US$1.7Bln CCS project started this week and injection is expected to ramp-up to 4 million tonnes of CO2 per year in the next few months. The partnership has now started one of the largest Greenhouse Gas (GHG) reduction projects ever undertaken. What an amazing accomplishment.
The Gorgon LNG plant produced over 9 million tonnes of CO2 during the initial year of production. Once the CCS project is at full injection rates, it will reduce the carbon intensity by about 40%. The 5 million tonnes of annual CO2 emissions remaining are mainly associated with the combustion of natural gas for power generation needed to run the liquefaction plant. Benchmarking the Carbon Intensity of the Gorgon LNG project to other major LNG projects around the world clearly shows the value of CCS, now achieving a competitive sub 0.4 tonnes of CO2 equivalent per tonne of LNG (tCO2/tLNG). The Gorgon partnership has delivered what many said was a myth.
However, a new wave of LNG projects is now being planned – with even better environmental or ‘green’ credentials. With a full natural gas supply chain Carbon Management strategy that reduces flaring, venting and fugitive emissions from upstream operations, and also liquefaction emissions reductions through use of electric drives and the integration of renewable power, sub 0.15 tCO2e/tLNG performance is achievable. Both Gorgon and these new planned projects clearly demonstrate that our industry continuously improves and will make further progress to deliver more energy with less emission.
Natural Gas – The cost of “free” gas
Much of the US gas news over the last few months has focused on the prodigious growth in gas production from the LTO activities in the Permian, and the gas flaring that has resulted. Dramatic headlines have accompanied the wild price fluctuation at the Waha hub, especially on those occasions where prices have been “negative”. In effect, producers have had to pay to have their gas taken away.
As we move inexorably towards a world where associated gas from oil production takes a larger and larger role, the question of how to value that gas will increasingly be at the forefront of development planning and economics. As well as commercial value drivers, regulatory developments that prevent routine flaring of gas will also start to take effect. The industry is rapidly moving to a place where a gas solution will be a pre-requisite to oil development everywhere, and so an increased focus on associated gas capture, processing, and utilization will be paramount.
For those not intimately familiar with the gas value chain, the inability to utilize “free” gas can be a puzzle. However, with many gas markets around the world now looking at low prices that few thought would be possible just a few years ago, the struggle to monetize gas at the wellhead is a real one. In particular, as the oil industry starts to develop areas prone to sour gas, CO2, or other impurities, the costs of simply cleaning the gas to a usable specification can be high, even if NGLs and condensates offer some economic support.
Many of the larger oil projects around the world, capable of development at today’s moderate oil prices, have large amounts of gas associated with them. Prospective developments in the Gulf of Mexico and the Brazilian pre-salt are good examples of developments that will require substantial amounts of associated gas to be gathered and treated, alongside CO2 capture for some regions.
With increasing LNG supply, and pipeline supplies in many parts of the world also on the rise, there appears to be little chance in the short to medium term that gas market prices will recover significantly. For oil developers, the choice will largely revolve around a decision to delay until a gas solution is found, or to use some of their oil revenue to pay for one. Subsidies from oil revenues to essentially buy a market for gas may sound unlikely, but this may be where the industry is headed. This will bring a whole host of regulatory and fiscal challenges, such as whether some sort of negative royalty or credit should be allowed. It may also force competing producers to collaborate on such things as gas gathering, processing and transmission, to minimize cost and create economies of scale. New business models may even emerge, with companies specializing in associated gas capture, treatment and sale, based on a tariff mechanism that represents little more than a disposal fee for the oil producer.
It has long been recognized that some part of the downward pressure on Henry Hub has resulted from Permian gas being forced onto a market that is already well supplied. As a result, the higher the price of oil, the lower the price of gas. With this phenomenon now starting to play out globally, the imperative to find new markets for natural gas in non-traditional areas is becoming even more important. Of course, the winners in all this continue to be gas customers, and power generators, for whom gas is now the obvious choice. However, with renewables increasingly taking market share, even gas-fired power may not be a reliable market in the longer term.
Crude Oil – Price dives on unexpected crude build
Oil prices tumbled after an unexpected build in US crude stockpiles and on fears of slowing demand.
EIA expects Brent crude oil prices will increase to $65 per barrel during the next several months and remain there throughout 2020. EIA expects this price to be a relatively stable price point for the market, considering modest levels of inventory growth in 2020 and IMO 2020 regulations going into effect. However, the combination of oil supply disruption risk and lower economic growth expectations in 2019 creates uncertainty.
In 2019, EIA forecasts that upward pressure on crude oil prices from supply-side constraints will be largely offset by demand-side concerns. In 2020, despite increased crude oil demand resulting from new regulations from the International Maritime Organization (IMO 2020), production is expected to increase more, offsetting the price impacts from increased demand.
EIA forecasts that total global production growth will increase year over year by 1.6 million barrels per day in 2020. US total liquids production drives the forecast global production growth, and EIA expects that it will average 19.8 million barrels per day in 2019 and increase by 1.5 million barrels per day to 21.3 million barrels per day in 2020.
Production from members of the Organization of the Petroleum Exporting Countries (OPEC) is expected to decrease in 2019 and in 2020 and offset some of the production increases from the US. Declining OPEC production is the result of Saudi Arabia’s over compliance with the December 2018 OPEC+ agreement in the first half of 2019 and rapidly decreasing crude oil production in Iran and Venezuela.
Crude Oil Price
Brent, the global benchmark for oil, decreased $4.22 to $58.40 a barrel, reflecting a loss of 6.74% on the week.
WTI crude fell $1.97 to $53.84 a barrel, down 3.53% on the week.
Total US rig count (including the Gulf of Mexico) stands at 934, down 8. The horizontal rig count stands at 817, down 2. US rig activity continues to decline and is 122 rigs below (-12%) last year’s total. US shale operators continue to focus on well productivity (i.e., well completion), DUC wells and operational efficiency over rig growth. Crude price continues to support capital discipline over production growth by the drill bit.
US Crude Oil Supply and Demand
Crude oil inventories increased 2.4 million barrels from the previous week. The crude stored at Cushing (the main price point for WTI) decreased 1.5 million barrels; total stored is 47.4 million barrels (~53% utilization).
US crude oil refinery inputs averaged 17.8 million barrels per day, with refineries at 96.4% of their operating capacity last week. This was 786,000 barrels per day more than the previous week’s average. With refiners increasing their utilization, product supplies are more than adequate as we head into the home stretch of the driving season.
US gasoline demand over the past four weeks was at 9.5 million barrels, down 1.8% from a year ago. Total commercial petroleum inventories increased by 10.4 million barrels last week.
US crude net imports averaged 5.3 million barrels per day last week, up by 1,194,000 barrels per day from the previous week. Over the past four weeks, crude oil net imports averaged 4.3 million barrels per day, 31% less than the same four-week period last year.
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