Below are a number of crude oil plus condensate (C + C ) production charts for Non-OPEC countries created from data provided by the EIA’s International Energy Statistics and updated to December 2021. This is the latest and most detailed world oil information available. Information from other sources such as OPEC, the STEO and country specific sites such as Russia, Brazil, Norway and China is used to provide a short term outlook for future output and direction for a few countries and the world.
December Non-OPEC production decreased by 261 kb/d to 49,628 kb/d. Of the 261 kb/d decrease, the biggest decreases came from the US 205 kb/d, Brazil 113 kb/d and China 91 kb/d. Offsetting the decreases were increases from Norway, 117 kb/d and Guyana 86 kb/d.
All of the oil (C + C) production data for the US state charts comes from the EIAʼ’s Petroleum Supply monthly PSM.
U.S. January production decreased by a surprising 216 kb/d to 11,371 kb/d. In December production dropped by 206 kb/d. The main declining states were Texas 120 kb/d, New Mexico 31 kb/d, and ND 24 kb/d. Of the top 10 states, only Colorado increased its production.
Below are a number of oil, crude plus condensate (C + C ), production charts for Non-OPEC countries created from data provided by the EIA’s International Energy Statistics and updated to November 2021. Information from other sources such as OPEC, the STEO and country specific sites such as Russia, Brazil, Norway and China is used to provide a short term outlook for future output and direction for a few countries and the world.
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.
