13th March 2020
Oil Drilling Activity
Onshore US drilling activity increased by 3 with a total active count of 771 (Y/Y decrease of 230) rigs; those targeting oil up 1, with the total at 683. Across the three major unconventional oil basins, the oilrig count increased 3, with Permian up 3, Williston and Eagle Ford flat.
US domestic crude production decreased 100,000 barrels per day last week; crude production stands at 13 million barrels per day, of which ~2.55 million barrels per day is offshore and Alaskan production.
The corona virus induced slump in oil demand is being compounded by the threat of a flood of cheap supply after Saudi Arabia and the United Arab Emirates indicated they would raise output in a standoff with Russia over production constraint.
During the last downturn between 2014 and 2016, companies slashed spending and ultimately were able to do more with less. There’s no fat left to trim in 2020, the cuts to development activity will be fast and brutal with the rig count in the US and elsewhere expected to decline sharply in Q2 2020.
Carbon Management – Methane measurement: the right methodology
During this time of market uncertainty, carbon management practices usually revert to those that can improve operating cash flow and generate returns in weeks and months, not years. Methane management is such a solution. Think of it as the containment phase for the coronavirus – if you get this wrong, then you will spend more on mitigation later. There are two ways to estimate methane emissions – “top down” and “bottom up”.
"Bottom-up" measures estimated emissions from a representative sample of devices. It calculates emissions based on activity factors and emission factors, i.e., number of gas production sites (activity factor) times average annual methane emissions per site (emissions factor (EF)). It is a source-specific quantification approach in that the emissions from each identified source are individually calculated. EFs provided by governments, academic publications, field measurement campaigns, gas industry research and/or equipment supplier data. The bottom-up quantification approach currently used by the industry to quantify and report its emissions.
"Top-down" measurements done at a regional scale using aerial methods, measuring methane concentrations in ambient air and calculating methane flux as a function of meteorological conditions. Top-down mainly relies on aircraft flying upwind and downwind of a study area but are increasingly using drones and satellite data.
Each method has its pros and cons but what stands out is that without temporal and spatial reconciliation, each type of study will produce a different result for the same region. Notably, the US published top-down studies generally estimate that emissions in a region are much higher than estimates based on bottom-up inventories of hydrocarbons and other sources, as much as five times higher.
Critics of the bottom-up method cite the following flaws in the methodology:
• Inaccurate data leading to underreporting – because it is source specific, every single source must be taken into account. Sources missed, undercounted, and activity factors can be out of date, incorrect or understated. Further, emissions factors can also be out of date, incorrect, or inaccurate.
• Bottom-up inventories may not fully capture all of the biogenic sources, which are captured in top-down.
• Component-based studies can under-sample abnormal operating conditions such as malfunctions and large leaks. “Super-emitters” are not accounted for, as average emission factors do not account for high emitting sites.
Conversely, flaws in the top-down method include:
• Temporal issues – Top-down estimates are generally based on only one or two measurement flights of limited duration (hours); the emission rates estimated from the data may not represent average emission rates over a longer time span. For example, in a recent National Academy of Science reconciliation study, the key source explaining the difference between top-down and bottom-up estimates was manual liquids unloading, where emissions usually occur during daytime operator shifts, which is also when meteorological conditions were ideal for aircraft methane emission measurements.
• Rather than source-specific, top-down is global and cannot attribute emissions to a source. It cannot determine whether the source is from agriculture, landfills, or hydrocarbon production.
• Atmospheric conditions and the presence of aerosols can distort results and lead to uncertainty.
The disparity between top-down and bottom-up methods have created conflicting views on the viability of natural gas over coal, and has clouded policy discussions on the best way to manage methane emissions. Today’s research indicates that neither top-down nor bottom-up estimates are “correct.” However, if they are reconciled for space and time and use detailed operational data, the ultimate result is as accurate as possible with today’s technology.
So what is next in methane measurement given the disparity between the two measurement approaches? In addition to the use of both approaches, and then reconciling them, leading environmental non-governmental organizations (eNGOs) have proposed three areas of improvement that appear to be suitable for practical, economic application:
1) Begin using direct field measurement and integrate the data into emissions estimates. Technology is rapidly developing in this space, and costs will come down as efficiencies are gained and more technologies come to market.
2) Increase the transparency and granularity of emissions reporting. Stakeholders should have access to the emissions factors, activity factors, and other data used to compute methane emission intensity.
3) Methane data should be validated or verified through a qualified and independent third party. The EU currently has a validation requirement for greenhouse gas emissions for industrial installations and aircraft operators, so this is not a novel approach. This requirement could easily translate to the oil and gas sector.
Contact us for confidential advice on determining the best approach for methane measurement for your particular situation.
Crude Oil – Opening the taps … high-cost producer is the target
Because of the outcome of the March 6 OPEC meeting, EIA’s March forecast assumes that OPEC will target market share instead of a balanced global oil market. EIA forecasts OPEC crude oil production will average 29.2 million barrels per day from April through December 2020, up from an average of 28.7 million barrels per day in the first quarter of 2020. EIA forecasts OPEC crude oil production will rise to an average of 29.4 million barrels per day in 2021.
There is nothing that the high-cost producers can do in the short-term, magnitude-wise, to offset what Saudi and the UAE announced in terms of incremental production. However, a year from now or even by the end of 2020, the slowdown among higher-cost producers in time will offset the increase in production from low-cost producers.
As we wait to see who will break first in the Saudi-Russian price war, both sides may have enough financial capacity and sufficiently divergent goals to sustain the oil price war for many quarters, not months.
The EIA and OPEC have slashed forecasts for oil demand because of the coronavirus outbreak and now expect demand to contract this quarter. If the crisis persists for several months, companies will go bankrupt, especially those in the US energy sector, which also have to deal with an oil price war. The EIA’s STO published March 11 forecasts WTI averaging $38/Bbl for 2020, with a partial recovery in 2021; but in the current turbulent market, they recognize a wide range of uncertainty in this forecast.
Weekly data on US inventories showed minimal effects from the coronavirus pandemic so far. Crude stocks increased by 7.7 million barrels, but inventories of gasoline and diesel fell sharply, as refining runs remain at seasonally low levels.
Total US rig count (including the Gulf of Mexico) stands at 792, down 1 last week. The horizontal rig count stands at 713, up 5. US rig activity continues to show constraint and is 236 rigs below (-23%) last year’s total.
US Crude Oil Supply and Demand
Crude oil inventories increased by 7.7 million barrels from the previous week, compared with last week’s modest build of 0.8 million barrels. The crude stored at Cushing (the main price point for WTI) increased 0.7 million barrels; total stored is 37.9 million barrels (~42% utilization). Total US commercial crude stored stands at 451.8 million barrels (~58% utilization).
US crude oil refinery inputs averaged 15.7 million barrels per day, with refineries at 86.4% of their operating capacity last week. This was 5,000 barrels per day more than last week’s average.
US gasoline demand over the past four weeks was at 9.1 million barrels, up 1.7% from a year ago. Total commercial petroleum inventories decreased by 7.6 million barrels last week.
US crude net imports averaged 3 million barrels per day last week, up by 918,000 barrels per day from the previous week. Over the past four weeks, crude oil net imports averaged 2.66 million barrels per day, 28.5% less than the same four-week period last year.
- GCA Oil & Gas Monitor
- Latin America
- North America
- Asia-Pacific & China
- Middle East
- Russia & Caspian
- Business of Energy
- Midstream & Downstream
- Gas & LNG
- Meet our Experts
- Project Experience Brochures
- Training Business
- GCA Oil & Gas Monitor: 2019 archive
- GCA Oil & Gas Monitor: 2018 archive
- US Oil & Gas Monitor: 2017 archive
- US Oil & Gas Monitor: 2016 archive
- US Oil & Gas Monitor: 2015 archive
We're here to help
Europe / Africa / Middle East / Russia & Caspian
gaffney-cline & associates