All of the Crude plus Condensate (C + C) production data for the US state charts comes from the EIAʼs November Petroleum Supply monthly PSM which provides updated information up to September 2022.
U.S. September production increased by 289 kb/d to 12,268 kb/d. It should be noted that August’s oil production was revised up by only 4 kb/d in the current September report. The large increase over the August update is real. For September, the states with the largest increase were Texas 90 kb/d, New Mexico 75 kb/d and North Dakota 43 kb/d. The Gulf of Mexico added 64 kb/d.
All of the Crude plus Condensate (C + C) production data for the US state charts comes from the EIAʼs September Petroleum Supply monthly PSM which provides data up to July 2022.
U.S. July production increased by a minimal 12 kb/d to 11,800 kb/d. For July, the states with increasing production were offset by states with decreasing production. July’s production was a new recent high. Production was 10 kb/d higher than November 2021 which was producing at a rate of 11,790 kb/d. However it should be noted that June’s oil production was revised down from 11,816 kb/d to 11,788 kb/d in the September report.
Each month the EIA produces four reports which project oil output for the US and the World. The Short Term Energy Outlook (STEO) forecasts oil output for a period of 12 to 24 months into the future for US and World oil production. A second report, the Drilling Productivity Report (DPR) forecasts the combined production for conventional and tight oil in the main tight oil basins, four months ahead of the EIA monthly report. Their third report, Light Tight Oil (LTO), reports on only the tight oil produced in seven tight oil basins and a few smaller ones. A fourth and final outlook is the Monthly Energy Review (MER) that forecasts US output two months past the official US production numbers, for this report that will be October and November. Due to technical issues at the EIA, the LTO report and the MER were not available at press time.
Production numbers/charts for May for four countries obtained from their official sites are provided below.
Normally the Outlooks report appears at the end of the monthly US report. For this month it has been posted separately and early.
1) Short Term Energy Outlook
The June STEO provides projections for the next 21 months, starting with April 2022 to December 2023, for US C + C and other countries.
The June 2022 STEO has revised downward its projected US oil output from May 2022 to Q3-23. However Q4-23 has been revised up from the previous May 2022 STEO. In December 2023 output is expected to reach 13,444 kb/d, 160 kb/d higher than reported in the May report
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.
