World Conventional Oil output peaked at a centered twelve month average (CTMA) of 74193 kb/d in July 2016. This peak is unlikely to be surpassed in the future. I do not include an estimate of unconventional oil produced in Venezuela as this data is difficult to find. In the chart below, I compare World C+C output to World conventional oil, which I define in this post as World C+C minus the sum of US tight oil and Canadian oil sands. The units for most charts (figures 11 and 12 are exceptions) will be kb/d on vertical axes. Data for oil output in all charts that follow will be the centered twelve month average output. Data is from the EIA’s International Energy Statistics.
The OPEC Monthly Oil Market Report (MOMR) for April 2022 was published last week. The last month reported in each of the charts that follow is March 2022 and output reported for OPEC nations is crude oil output in thousands of barrels per day (kb/d). In most of the charts that follow the blue line is monthly output and the red line is the centered twelve month average (CTMA) output.
The OPEC Monthly Oil Market Report (MOMR) for March 2022 was published this week. The last month reported in each of the charts that follow is February 2022 and output reported for OPEC nations is crude oil output in thousands of barrels per day (kb/d). In most of the charts that follow the blue line is monthly output and the red line is the centered twelve month average (CTMA) output.
Much of the information for this post comes from data at shaleprofile , and assessments by the USGS. In addition a paper published in Jan 2022 by Wardana Saputra et al was an excellent resource.
The basic method used in the is analysis is covered in an earlier post, essentially the convolution of average well profiles with the monthly completion rate over time is used to model future output. I focus on the period starting in Jan 2010 and consider only horizontal tight oil wells in the analysis. Future well profiles are estimated and several future scenarios for completion rate are used, clearly the future is unknown so future completion rates and estimated ultimate recovery (EUR) for wells completed in the future can only be guessed at.
In order to make such a guess I start with the USGS assessments for the Permian basin where the mean estimate for prospective net acres as of mid 2017 was about 50 million acres. I use an estimate for average acres per well of 300 acres (about 9500 feet lateral length with spacing of 1320 feet between laterals) which gives an estimate of about 167 thousand wells. There were about 14 thousand wells already completed in the Permian basin by June 2017 so total completions would be about 181 thousand wells, if oil prices were high enough to make every potential well location profitable. Using the mean UTRR estimate (70 Gb) and number of potential drilling locations (about 160 thousand as of Dec 21, 2021 based on the data at shale profile where about 21 thousand wells were completed from July 2017 to Dec 2021), I find and estimate for the future decrease in EUR per well that will result in a UTRR of 70 Gb if all potential wells were completed.
After that step a discounted cash flow analysis using guesses of future costs and prices is used to determine whether a well will be profitable to complete to arrive at an ERR for a given scenario, typically ERR is less than TRR, but in rare high oil price scenarios they could be nearly equal.
Average well profiles have been developed by fitting an Arps hyperbolic function to the data from shaleprofile.com for the average 2010 to 2012 well and then for each individual year from 2013 to 2020. In my scenarios I assume EUR starts to decrease after Dec 2020 and assume no further increase in lateral length or change in average well spacing.
