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Duly noted.
Mrs. Smith
BSEE Monitors Gulf of Mexico Oil and Gas Activities in Response to Hurricane Ida, Updated 9/17/202
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-monitors-gulf-of-mexico-oil-and-68
NEW ORLEANS — Bureau of Safety and Environmental Enforcement (BSEE) activated its Hurricane Response Team as Hurricane Ida made its way through the Gulf. The Hurricane Response Team continues to monitor offshore oil and gas operators in the Gulf as they return to platforms and rigs after the storm. The team works with offshore operators and other state and federal agencies until operations return to normal.
Based on data from offshore operator reports submitted as of 11:30 CDT today, personnel are still evacuated from a total of 41 production platforms, 7.32 percent of the 560 manned platforms in the Gulf of Mexico. Production platforms are the structures located offshore from which oil and gas are produced. Unlike drilling rigs, which typically move from location to location, production facilities remain in the same location throughout a project’s duration.
All non-dynamically positions rigs are currently operating in the Gulf. Rigs can include several types of offshore drilling facilities including jackup rigs, platform rigs, all submersibles and moored semisubmersibles.
A total of 2 dynamically positioned rigs remain off location. This number represents 13.33 percent of the 15 DP rigs currently operating in the Gulf. Dynamically positioned rigs maintain their location while conducting well operations by using thrusters and propellers. These rigs are not moored to the seafloor; therefore, they can move off location in a relatively short time frame. Personnel remain on-board and return to the location once the storm has passed.
As part of the evacuation process, personnel activate the applicable shut-in procedure, which can frequently be accomplished from a remote location. This involves closing the sub-surface safety valves located below the surface of the ocean floor to prevent the release of oil or gas, effectively shutting in production from wells in the Gulf and protecting the marine and coastal environments. Shutting in oil and gas production is a standard procedure conducted by industry for safety and environmental reasons.
From operator reports, it is estimated that approximately 23.19 percent of the current oil production in the Gulf of Mexico is shut in. BSEE estimates that approximately 34.33 percent of the gas production in the Gulf of Mexico is shut in. The production percentages are calculated using information submitted by offshore operators in daily reports. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day. The shut-in production figures therefore are estimates, which BSEE compares to historical production reports to ensure the estimates follow a logical pattern.
Facilities are currently being inspected. Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back online.
Hurricane Ida disrupted crude oil production and refining activity
https://www.eia.gov/todayinenergy/detail.php?id=49576#
On Sunday, August 29, Hurricane Ida made landfall near Port Fourchon, Louisiana, as a Category 4 hurricane. As a result of the hurricane, 96% of crude oil production and 94% of natural gas production in the U.S. federally administered areas of the Gulf of Mexico (GOM) were shut in, according to estimates by the U.S. Department of Interior’s Bureau of Safety and Environmental Enforcement. At least nine refineries shut down or reduced production. As a result, we reduced our forecast for crude oil production and refinery runs in our September Short-Term Energy Outlook (STEO).
We revised down our estimate for U.S. crude oil production in the GOM in August by 0.2 million barrels per day (b/d) from the August STEO to 1.5 million b/d in the September STEO. We reduced our forecast of production in the GOM for September by 0.5 million b/d from the August STEO to 1.2 million b/d in the September STEO. We expect that disrupted GOM crude oil production will return through September, increasing to our previously forecast levels in October. Last year, the GOM accounted for 15% of U.S. crude oil production.
According to our Weekly Petroleum Status Report, gross inputs into Gulf Coast refineries fell by 1.6 million b/d from the week ending August 27 to the week ending September 3. Although some refiners have resumed operations or begun the process for restarting, we expect refinery runs will average 713,000 b/d lower in September than they would have without the disruptions.
Repairs to any infrastructure required to resume refinery operations, however, could potentially take longer, making the forecast highly uncertain. We forecast that average crude oil inputs into refineries later this year will be mostly unchanged from our previous August STEO forecast.
From August 27 to September 3, our Weekly Petroleum Status Report data indicate crude oil inventories in the Gulf Coast fell by 2.6 million barrels and U.S. crude oil production fell by 1.5 million b/d. Over the same period, crude oil imports into the Gulf Coast fell by 247,000 b/d to 787,000 b/d. U.S. crude oil exports, which are mostly exported from the Gulf Coast, fell by 698,000 b/d over the same period.
On September 14, Hurricane Nicholas made landfall as a Category 1 storm about 50 miles south of Houston. As a result of power outages, Colonial Pipeline (which runs from Houston up the East Coast of the United States) shut down two product pipelines. Trade press reports indicate that Colonial has resumed normal operations on both lines. The Houston Ship Channel was closed to traffic on September 13, but normal operations are expected to resume September 15.
The U.S. exported slightly more petroleum than it imported in the first half of 2021, Released 9/17/2021
https://www.eia.gov/todayinenergy/detail.php?id=49596
Source: U.S. Energy Information Administration “EIA”
Our Petroleum Supply Monthly trade data show that the United States exported more crude oil and petroleum products than it imported during the first half of 2021 by 120,000 barrels per day (b/d), or less than 1% of combined crude oil and petroleum product exports and imports.
The United States was a net importer of crude oil and petroleum products (imported more than it exported) in the first of half of each year until the first half of 2020, when the United States became a net exporter (exported more than it imported) by 432,000 b/d of crude oil and petroleum products. This year marks only the second time the United States has been a net total petroleum exporter in the first half of the year. The United States has been a net exporter of petroleum products alone since 2011.
The United States exports more refined petroleum products than it does crude oil. Petroleum product exports averaged 5.5 million b/d in the first half of 2021, up from 5.3 million b/d in the first half of last year. Exports of petroleum products include motor gasoline, distillate, and propane exports. Both imports and exports of select petroleum products mainly consumed as transportation fuels—distillate fuel oil, motor gasoline, and jet fuel—altogether decreased in 2020 compared with 2019.
Propane exports increased in response to more demand for propane in Asia and less demand for propane in the United States. Propane now surpasses distillate fuel oil as the most prevalent U.S. petroleum product export by volume. In the first half of 2021, both imports and exports of petroleum products increased above their levels in the first halves of 2020 and 2019.
The United States imports more crude oil than it does petroleum products. The United States was a net importer of 2.9 million b/d of crude oil in the first half of 2021. Net imports of crude oil have decreased in the first half of every year since 2017, primarily reflecting increasing U.S. exports of crude oil since the end of the U.S. crude oil export ban in 2015.
Gross U.S. crude oil exports in the first half of 2021 averaged 3.0 million b/d, down from 3.2 million b/d in the first half of last year. This decrease was the first time exports decreased since the end of the export ban in 2015 and was likely driven by lower crude oil production, which decreased substantially in 2020 because of economic responses to the COVID-19 pandemic. Gross U.S. crude oil imports also fell, decreasing from 6.2 million b/d in the first half of 2020 to 5.9 million b/d in the first half of 2021.
Too “complicated for this GSPE board”?
Darn it! Now we will miss out on what spec would have proposed, and any spreadsheets I could have pulled together.
In all seriousness, the majority of us (with very few exceptions) are fast learners. I am not saying we will understand all aspects, but we should grasp the essentials.
Either way, thank you for your high level of board contributions.
Mrs. Smith
Upon completion of the Tau 1 test well, Delek Group’s Tau Prospect 6/2019 “NSAI” Netherland, Sewell and Associates, Inc. “Resource” report included two additional target layers, M5 and M6 when compared to the previous 2017 NSAI report. Based on 100% working interest those two target layers contributed on the “High Estimate” roughly 400 MM BOE of “Prospective Resources”. The NPV10 on that additional 400 MM BOE assuming a flat rate pricing of $55/bbl and $2.25 mcf less Finding, Development and Operating costs comes to roughly 4.3 billion.
In addition, based on 100% working interest the Tau Prospect’s overall “average net layer thickness” in feet on the 2019 NSAI report increased by 631 feet for a total of 1,325 feet when compared to the 2017 report.
I will repeat, “you gain a lot of data when drilling a hole”. Netherland, Sewell and Associates, Inc. reported on the Tau Prospect’s 6/2019 resource report “the quality of sands discovered at the Tau-1 Well was better than expected”.
Delek Group holds 75% of the asset rights in the BOEM leases in the area of which the Tau 2 twin well will be drilled, they are a 24% Capital Shareholder in GSPE, Gulfslope Energy holds 25% of the asset rights and is STILL the Operator of the Tau Prospect.
When producing you are depleting your assets, so sustained growth (finding other accumulations) is required, otherwise you are going out of business one day at a time. That is the essence of the oil business. It is what keeps shareholders happy and geologists employed.
Mrs. Smith
Weekly Petroleum Status Report, Released Sept. 15, 2021, Data for week ending Sept. 10, 2021
Full Report with Graphs/Tables: https://www.eia.gov/petroleum/supply/weekly/pdf/wpsrall.pdf
Data Overview: https://ir.eia.gov/wpsr/overview.pdf
WTI $72.81/bbl September Contract: https://oilprice.com/oil-price-charts/45
Crude Oil WTI Futures - Oct 21: https://www.investing.com/commodities/crude-oil-technical
HIGHLIGHTS
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 6.4 million barrels from the previous week. At 417.4 million barrels, U.S. crude oil inventories are about 7% below the five year average for this time of year. Total motor gasoline inventories decreased by 1.9 million barrels last week and are about 4% below the five year average for this time of year. Finished gasoline and blending components inventories both decreased last week. Distillate fuel inventories decreased by 1.7 million barrels last week and are about 13% below the five year average for this time of year. Propane/propylene inventories increased by 0.7 million barrels last week and are about 20% below the five
year average for this time of year. Total commercial petroleum inventories decreased by 8.8 million barrels last week.
U.S. crude oil refinery inputs averaged 14.4 million barrels per day during the week ending September 10, 2021 which was 85,000 barrels per day more than the previous week’s average. Refineries operated at 82.1% of their operable capacity last week. Gasoline production decreased last week, averaging 9.3 million barrels per day. Distillate fuel production decreased last week, averaging 4.2 million barrels per day.
U.S. crude oil imports averaged 5.8 million barrels per day last week, down by 48,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.0 million barrels per day, 13.3% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 638,000 barrels per day, and distillate fuel imports averaged 164,000 barrels per day.
Total products supplied over the last four-week period averaged 21.1 million barrels a day, up by 16.9% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.4 million barrels a day, up by 8.1% from the same period last year. Distillate fuel product supplied averaged 4.0 million barrels a day over the past four weeks, up by 10.9% from the same period last year. Jet fuel product supplied was up 59.1% compared with the same four-week period last year.
The West Texas Intermediate crude oil price was $69.82 per barrel on September 10, 2021, $0.48 above last week’s price and $32.49 more than a year ago. The spot price for conventional gasoline in the New York Harbor was $2.307 per gallon, $0.032 less than last week’s price but $1.152 above a year ago. The spot price for ultra-low sulfur diesel fuel in the New York Harbor was $2.140 per gallon, $0.017 below last week’s price but $1.053 over a year ago.
The national average retail regular gasoline price was $3.165 per gallon on September 13, 2021, $0.011 per gallon less than last week’s price but $0.982 over a year ago. The national average retail diesel fuel price was $3.372 per gallon, $0.001 below last week’s price but $0.950 over a year ago.
What is providing the pressure for the water?
Could be the hydrostatic weight of the drilling fluid has exceeded the pressure gradient of the formation. Resulting in fracturing of the formation, loss of fluid, failure to keep the hole full which allows any formation pressure to flow back into the wellbore, i.e. “well control”.
“MPD” Managed Pressure Drilling systems help avoid that situation.
Mrs. Smith
Nothing provides better data than drilling a hole. The logs will show if there is oil, water or gas.
Geologists tell you where to drill. Engineers drill the hole. And the logs will tell you what you found.
Mrs. Smith
Depending on the casing design that might be a viable alternative, but could also add mechanical risks due to starting with a smaller casing size. Do they not already have two sidetracks and a bypass on Tau 1?
I recommend to go first class all the way, because this may be Gulfslope’s last chance.
MPD could make all the difference.
But I am not a drilling engineer, so what do I know?
Mrs. Smith
Excerpt: BSEE is reporting zero rigs evacuated in the GOM as of 11:00 am this morning. BSEE estimates approximately 39.57 percent of the current oil production in the Gulf of Mexico is shut in. In addition, BSEE estimates that approximately 48.20 percent of the gas production in the Gulf of Mexico is shut in.
BSEE Monitors Gulf of Mexico Oil and Gas Activities in Response to Hurricane Ida, Updated 9/14/2021
NEW ORLEANS — Bureau of Safety and Environmental Enforcement (BSEE) activated its Hurricane Response Team as Hurricane Ida made its way through the Gulf. The Hurricane Response Team continues to monitor offshore oil and gas operators in the Gulf as they return to platforms and rigs after the storm. The team works with offshore operators and other state and federal agencies until operations return to normal.
Based on data from offshore operator reports submitted as of 11:30 CDT today, personnel are still evacuated from a total of 39 production platforms, 6.69 percent of the 560 manned platforms in the Gulf of Mexico.. Production platforms are the structures located offshore from which oil and gas are produced. Unlike drilling rigs, which typically move from location to location, production facilities remain in the same location throughout a project’s duration.
All non-dynamically positions rigs are currently operating in the Gulf. Rigs can include several types of offshore drilling facilities including jackup rigs, platform rigs, all submersibles and moored semisubmersibles.
A total of 2 dynamically positioned rigs remain off location. This number represents 13.33 percent of the 15 DP rigs currently operating in the Gulf. Dynamically positioned rigs maintain their location while conducting well operations by using thrusters and propellers. These rigs are not moored to the seafloor; therefore, they can move off location in a relatively short time frame. Personnel remain on-board and return to the location once the storm has passed.
As part of the evacuation process, personnel activate the applicable shut-in procedure, which can frequently be accomplished from a remote location. This involves closing the sub-surface safety valves located below the surface of the ocean floor to prevent the release of oil or gas, effectively shutting in production from wells in the Gulf and protecting the marine and coastal environments. Shutting in oil and gas production is a standard procedure conducted by industry for safety and environmental reasons.
From operator reports, it is estimated that approximately 39.57 percent of the current oil production in the Gulf of Mexico is shut in. BSEE estimates that approximately 48.20 percent of the gas production in the Gulf of Mexico is shut in. The production percentages are calculated using information submitted by offshore operators in daily reports. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day. The shut-in production figures therefore are estimates, which BSEE compares to historical production reports to ensure the estimates follow a logical pattern.
Facilities are currently being inspected. Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back online.
Your sentiment is not shared among all regarding the Tau 2 twin well. An abundance of data was compiled from the Tau 1 test well.
You do not even know what really happened on the Tau 1.
Mrs. Smith
OPEC September 2021 Monthly Oil Market Report “MOMR”, Released September 13, 2021
Note: Edited to include just released MOMR video
9/2021 MOMR PDF: https://momr.opec.org/pdf-download/res/pdf_delivery_momr.php?secToken2=accept
9/2021 MOMR VIDEO: https://players.brightcove.net/34306109001/default_default/index.html?videoId=6272319066001
OIL MARKET HIGHLIGHTS
Crude Oil Price Movements
The OPEC Reference Basket (ORB) averaged $70.33/b in August, representing a decline of $3.20 m-o-m, or 4.4%. Year-to-date (y-t-d), ORB was $25.42, or 62.8%, higher, averaging $65.93/b. Crude oil futures prices on both sides of the Atlantic moved sharply lower in August, reaching their lowest levels since last May, as concerns about short-term Asian oil demand, mixed economic data, and the prospect of higher global oil supply triggered a sell-off. In August, the ICE Brent front-month declined $3.78 m-o-m, or 5.1%, to average $70.51/b, and NYMEX WTI fell $4.72 m-o-m, or 6.5%, to average $67.71/b. Consequently, the Brent/WTI front-month futures spread widened in August by 94¢ to average $2.80/b, its strongest since May. The market structure of all three major crude benchmarks – ICE Brent, NYMEX WTI, and DME Oman – remained in backwardation, however, their respective forward curves flattened on uncertainty about the oil demand outlook, lower seasonal crude demand in Asia, and the prospect of rising global oil supply. In August, hedge funds and other money managers extended the previous month's sell-off, reducing their net long positions to the lowest since November 2020.
World Economy
Global economic growth forecasts for both 2021 and 2022 remain unchanged from the last month’s assessment at 5.6% and 4.2% respectively. However, this robust growth continues to be challenged by uncertainties such as the spread of COVID-19 variants and pace of vaccine rollouts worldwide, as well as ongoing global supply-chain disruptions. Additionally, sovereign debt levels in many regions, together with inflationary pressures and central bank responses, remain key factors requiring close monitoring. In the current recovery, the US economy forecasts are unchanged at 6.1% for 2021 and 4.1% for 2022. Euro-zone economic growth remains at 4.7% for 2021 and 3.8% for 2022. The forecast for Japan is also unchanged at 2.8% for 2021 and 2.0% in 2022. China’s economy is seen to grow at 8.5% in 2021 and 6% in 2022, in line with the previous month’s assessment. Meanwhile, India’s 2021 growth forecast is revised slightly down to 9%, following a weaker-than-expected recovery in 2Q21, although growth for 2022 remains unchanged at 6.8%. Given strong growth in 2Q21, Brazil’s growth forecast for this year is revised up to 4.7%, while grow in 2022 is unchanged at 2.5%. Russia’s forecast for 2021 is revised up to 3.5%, benefitting from the stabilised oil market, while the forecast for 2022 remains unchanged at 2.5%.
World Oil Demand
World oil demand growth in 2021 remains unchanged from last month’s assessment, showing growth of 6.0 mb/d despite some offsetting revisions. Oil demand in 3Q21 has proved to be resilient, supported by rising mobility and travelling activities, particularly in the OECD. At the same time, the increased risk of COVID-19 cases primarily fuelled by the Delta variant is clouding oil demand prospects going into the final quarter of the year, resulting in downward adjustments to 4Q21 estimates. As a result, 2H21 oil demand has been adjusted slightly lower, partially delaying the oil demand recovery into 1H22. Global oil demand in 2021 is now estimated to average 96.7 mb/d. In 2022, oil demand is expected to robustly grow by around 4.2 mb/d, some 0.9 mb/d higher compared to last month’s assessment. Revisions were driven by both the OECD and non-OECD, as the recovery in various fuels is expected to be stronger than anticipated and further supported by a steady economic outlook in all regions. Oil demand in 2022 is now projected to reach 100.8 mb/d, exceeding pre- pandemic levels.
World Oil Supply
Non-OPEC liquids supply growth in 2021 is revised down by 0.17 mb/d from the previous month’s assessment, due to a downward adjustment of 0.5 mb/d in 3Q21. The revisions are mainly due to outages in North America from a fire on a Mexico’s offshore platform and the disruptions caused by Hurricane Ida. The estimate for North Sea production has also been revised down due to lower-than-expected output in 3Q21, resulting in an annual growth forecast of 0.9 mb/d to average 63.8 mb/d. The main drivers for 2021 supply growth remain to be Canada, Russia, China, the US, Brazil and Norway, with the US expected to see y-o-y growth of only 0.08 mb/d. The non-OPEC supply growth forecast for 2022 is unchanged at 2.9 mb/d, amid offsetting revisions, to average 66.8 mb/d. The main drivers of liquids supply growth are Russia and the US, followed by Brazil, Norway, Canada, Kazakhstan, Guyana and other countries in the DoC. OPEC NGLs are forecast to grow by 0.1 mb/d in both 2021 and 2022 to average 5.2 mb/d and 5.3 mb/d, respectively. OPEC crude oil production in August increased by 0.15 mb/d m-o-m, to average 26.76 mb/d, according to available secondary sources.
Product Markets and Refining Operations
Global refinery margins continued to trend upwards, supported by the seasonal strength in transportation fuels, amid easing mobility restrictions. In the US, product markets were supported by a reduction in total product inventory levels, while seasonal support pushed gasoline margins to new record highs. In Europe, refining margins benefitted from a positive performance across the barrel, while a contraction in fuel outputs from key traditional fuel suppliers within the region helped strengthen European product markets. Meanwhile, in Asia, weakness from rising regional fuel output levels were overshadowed by the robust performance in the jet fuel- kerosene and fuel oil markets, driven by an improvement in summer-related air travel and cooling requirements. Robust fuel consumption levels in India added to the upturn in regional refining economics.
Tanker Market
The VLCC tanker rates remained at depressed levels in August, weighed down by ample tonnage availability despite increased tanker demand. Suezmax and Aframax rates managed a better performance in intra-Asian routes, as well as the Atlantic basin, particularly from West Africa to the US Gulf. Clean tanker rates showed a healthy improvement East of Suez but slipped in the West. The arrival of Hurricane Ida in the Gulf of Mexico at the end of the month resulted in temporary dislocations, lending some support to dirty Aframax rates, while depressing clean rates in the early days of September as Gulf Coast refineries remain offline.
Crude and Refined Products Trade
Preliminary data shows US crude imports averaged 6.3 mb/d in August, while crude exports recovered to just under 3.0 mb/d. US product imports rose m-o-m to a robust 2.6 mb/d, while product exports averaged 5.3 mb/d in August, as lower demand from Latin America offset higher flows to Asia. Disruptions caused by Hurricane Ida at the end of August will likely impact these crude and product flows in September, as oil installations along the US Gulf Coast seek to restart. China’s crude imports averaged 9.7 mb/d in July, remaining relatively flat since April, although recently released data for August shows crude inflows jumping to 10.5 mb/d now that refiners have a further round of quotas. India’s crude imports continued to fall in July, averaging 3.6 mb/d, but positive expectations remain for a pick-up in August, as state-owned refiners look to increase runs to maximum capacity during 4Q21. Japan’s crude imports averaged 2.1 mb/d in July, as the country’s COVID-19 state of emergency continued to weigh on refinery runs amid uncertainty about product demand.
Commercial Stock Movements
Preliminary data shows total OECD commercial oil stocks up by 10.5 mb m-o-m in July. At 2,912 mb, inventories were 305.9 mb lower than the same month a year ago; 122 mb below the latest five-year average; and 57.2 mb lower than the 2015-2019 average. Within components, crude stocks fell by 5.6 mb m-o-m while product stocks rose by 16.1 mb. At 1,404 mb, crude stocks in the OECD were 106.9 mb below the latest five-year average and 80.0 mb below the 2015-2019 average. Meanwhile, OECD product stocks averaged 1,508 mb, representing a deficit of 15.1 mb compared with latest five-year average, but 22.7 mb above the 2015-2019 average. In terms of days of forward cover, OECD commercial stocks rose 0.1 day m-o-m to stand at 63.7 days in July. This is 11.6 days below the same month last year and 1.2 days below the latest five-year average, but 1.5 days above the 2015-2019 average.
Balance of Supply and Demand
Demand for OPEC crude in 2021 is revised up by 0.3 mb/d from last month’s assessment to stand at 27.7 mb/d, representing an increase of 4.9 mb/d over the previous year. Demand for OPEC crude in 2022 is revised up by 1.1 mb/d to stand at 28.7 mb/d, around 1.1 mb/d higher than in 2021.
BuckD would you like me to answer that Gulfslope question for you? On second thought, I better not.
Mrs. Smith
September Federal Reserve Bank of Dallas ”Energy Slideshow”, Released September 9, 2021.
See link below for slideshow charts on Energy Prices, Global Petroleum Data, National Outlook Data, and Regional Activity:
https://www.dallasfed.org/-/media/Documents/research/energy/energycharts.pdf?la=en
Mrs. Smith
BSEE Monitors Gulf of Mexico Oil and Gas Activities in Response to Hurricane Ida, Updated 09/13/2021
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-monitors-gulf-of-mexico-oil-and-64
NEW ORLEANS — Bureau of Safety and Environmental Enforcement (BSEE) activated its Hurricane Response Team as Hurricane Ida made its way through the Gulf. The Hurricane Response Team continues to monitor offshore oil and gas operators in the Gulf as they return to platforms and rigs after the storm. The team works with offshore operators and other state and federal agencies until operations return to normal.
Based on data from offshore operator reports submitted as of 11:30 CDT today, personnel are still evacuated from a total of 47 production platforms, 8.39 percent of the 560 manned platforms in the Gulf of Mexico. Production platforms are the structures located offshore from which oil and gas are produced. Unlike drilling rigs, which typically move from location to location, production facilities remain in the same location throughout a project’s duration.
Personnel are still evacuated from 1 rig (non-dynamically positioned), equivalent to 9.09 percent of the 11 rigs of this type currently operating in the Gulf. Rigs can include several types of offshore drilling facilities including jackup rigs, platform rigs, all submersibles and moored semisubmersibles.
A total of 2 dynamically positioned rigs remain off location. This number represents 13.33 percent of the 15 DP rigs currently operating in the Gulf. Dynamically positioned rigs maintain their location while conducting well operations by using thrusters and propellers. These rigs are not moored to the seafloor; therefore, they can move off location in a relatively short time frame. Personnel remain on-board and return to the location once the storm has passed.
As part of the evacuation process, personnel activate the applicable shut-in procedure, which can frequently be accomplished from a remote location. This involves closing the sub-surface safety valves located below the surface of the ocean floor to prevent the release of oil or gas, effectively shutting in production from wells in the Gulf and protecting the marine and coastal environments. Shutting in oil and gas production is a standard procedure conducted by industry for safety and environmental reasons.
From operator reports, it is estimated that approximately 43.60 percent of the current oil production in the Gulf of Mexico is shut in. BSEE estimates that approximately 51.61 percent of the gas production in the Gulf of Mexico is shut in.. The production percentages are calculated using information submitted by offshore operators in daily reports. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day. The shut-in production figures therefore are estimates, which BSEE compares to historical production reports to ensure the estimates follow a logical pattern.
Facilities are currently being inspected. Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back online.
FEATURED ARTICLE - OPEC September 2021 “MOMR” Monthly Oil Market Report. Released 9/13/2021
’Assessment of the global economy in 2021 and 2022’
Although the global economy continues to be affected by developments related to COVID-19, 1H21 saw a healthy economic recovery. Following the strong quarterly economic growth in 3Q21, growth is forecast to slightly decelerate towards the end of the year. It should be noted that the recovery this year has been widely supported by unprecedented government-led stimulus, and global efforts done to contain COVID-19, particularly in Western economies and China. Assuming a recovery in global consumption and investment growth in 2021, global GDP growth is forecast at 5.6%. However, a further rise in COVID-19 infections, especially considering the upcoming winter season in the Northern Hemisphere, could dampen current growth projections. In addition, ongoing global supply chain disruptions, rising sovereign debt levels in many regions, together with inflationary pressures and central bank responses, remain key factors that require close monitoring. Healthy growth is also projected for 2022, with the GDP rising by 4.2%. This will be supported by ongoing fiscal and monetary stimulus and continued efforts to contain COVID-19 infections. Upside to both annual growth levels may come from further US fiscal stimulus and improvements in developments related to COVID-19.
In terms of a geographical breakdown, the OECD shows a strong rebound in 2021, led by the US. US growth is forecast at 6.1% in 2021, supported by unprecedented fiscal and monetary stimulus. This is followed by projected growth of 4.1% in 2022, with further potential upside that may come from additional fiscal stimulus. Growth in the Euro-zone has also picked up strongly, especially in 2Q21, with economic growth for the entire year forecast at 4.7%, followed by 3.8% in 2022. Japan is facing ongoing COVID-19- related challenges and its economy is forecast to expand by 2.8% in 2021 and by 2% in 2022, albeit current domestic political changes and potential fiscal decisions may require revisions to these projections in the months to come.
In the non-OECD, the economic recovery has continued, though the pace and dynamics vary within the regions. China’s 1H21 GDP figures confirmed a stable economic recovery, albeit the renewed COVID-19 variant outbreak is forecast to limit 2021 growth at 8.5%. China’s anticipated softening of the 2H21 growth momentum is forecast to continue into 2022, leading to growth of 6%. India’s growth is forecast at 9% for 2021 and 6.8% in 2022.
Notwithstanding, there are still considerable uncertainties related to COVID-19 in India, as well as the likelihood of rising inflation. Growth forecasts for 2021 in Brazil and Russia stand at 4.7% and at 3.5%,
respectively, followed by 2022 growth of 2.5% in both economies. However, rising inflationary pressures have already led Brazil and Russia to lift key interest rates in recent months, potentially dampening the recovery going forward.
The global economic recovery, in combination with a considerable rebound in mobility, significantly lifted oil demand growth in 1H21. While this dynamic is forecast to soften towards the end of 2021, the overall positive trend has led to projected global oil demand growth of 6.0 mb/d for 2021, followed by growth of 4.2 mb/d in 2022. Non-OPEC supply is expected to grow by 0.9 mb/d in 2021, followed by forecast growth of 2.9 mb/d in 2022. Nevertheless, numerous uncertainties, including the continued COVID-19 impact on the global economic recovery, will require continued coordinated policies, including the commendable efforts undertaken by OPEC and non-OPEC oil producers participating in the Declaration of Cooperation (DoC), to ensure stability and balance for the global oil market.
Very thought-provoking reading the posts regarding lithium.
In the U.S we are using all the electricity that is being generated. If we replace even 1/3 of the vehicles with electric vehicles, who is going to go without power when they are being charged?
Wind and Solar do not contribute at the peak charging periods, which will be overnight. So power generation will have to be from natural gas or coal.
That means DRILLING, and the GOM produces a lot of gas.
Is it not cheaper to use a modified internal combustion engine?
The way I see it oil and gas will be in demand for decades to come. I would be hesitant to take the lithium plunge.
Mrs. Smith
There’s Only One Way to Rock, John Eichberger | August 2021
https://www.fuelsinstitute.org/Resources/The-Commute/There-is-Only-One-Way-to-Rock
https://www.fuelsinstitute.org/CMSPages/GetFile.aspx?guid=1d06a94b-0ce2-4d3d-9f75-bdff8ab77f84
If you pay attention only to the headlines, it would be very easy to believe that there is only one path to reducing carbon emissions from the transportation sector – electrification. National and regional governments continue to announce plans to phase out the internal combustion engine (ICE) and push for battery electric vehicles (BEV) and fuel cell electric vehicles (FCEVs) powered by hydrogen. Each of these technologies have a lot to offer and will provide great benefits to consumers and the environment, but they may not be applicable to all use cases and, despite government efforts, the market’s transition to these vehicles will take a very long time. To have a more immediate and long-lasting effect on the market that ultimately benefits consumers, we must explore more options than just these two technologies.
In thinking about what song to attach to the topic of this edition of The Commute, I was fortunate to ask Alexa to play Sammy Hagar and the second song that she played for me was “There’s Only One Way to Rock.” It seems appropriate, because there are so many different ways to address the emissions challenges facing the market in a way that will ultimately benefit the consumer that we have to keep our eyes open. Sammy talks about how rock has been “called by different names all over the world, but it’s all the same.” I feel the same about what we as society are trying to achieve with transportation – lower emissions coupled with reliable and affordable mobility. My primary concern these days is that we seem to be short cutting the work that must be done and regressing to a singular solution, which is not a “sustainable” strategy.?
The Bright Future for Electric and Fuel Cell Vehicles
There is no doubt that momentum continues to grow for these zero tailpipe emission vehicles – from government initiatives to manufacturer announcements, the future is bright. Despite these continuing developments, I remain cautious about forecasts for market expansion. From history, we can learn that the vast majority of projections are wrong because they do not take into consideration the unexpected. Who would have imagined the semiconductor chip shortage the market is dealing with this year that has forced the temporary closure of several vehicle manufacturing facilities? Who would have thought dealerships would be offering far above Kelley Blue Book value for our trades simply to have inventory to sell? These types of unforeseen dynamics wreak havoc on forecasts
I wrote a few months ago about the history of the hybrid electric vehicle (HEV). Years ago, I read projections indicating that more than 100 new HEV models would soon be available. Over the past 20 years, the U.S. has never featured more than 55 different hybrid vehicles. So, when I hear projections of more than 500 BEVs to be offered globally within the next few years, I read with a healthy dose of skepticism because there are always events that undermine the best intentions.
That said, there is no denying the momentum behind efforts to increase EV sales and that is evident in the actual performance of these vehicles at retail. The second quarter of 2021 alone recorded more BEV sales that the entire year of 2017 and BEVs accounted for ONLY 2.4% of all light duty vehicle (LDV) sales – up from 2.0% in first quarter and just 1.6% in 2020.
Keep an Eye on the Big Picture
The acceleration in sales is noteworthy and impressive, ]but we must continue to look at the market in context. Since 2013, U.S. consumers have purchased 141.6 million new LDVs. Of those, 98.6% have been powered by gasoline, diesel or a gasoline-battery hybrid system. How long might we expect these vehicles to remain on the road?
As you may have seen in past editions of this column, we have run the numbers based upon historical new vehicle sales and scrappage rates and know that it would take a decade for a new technology to reach 50% market share IF that technology was included in every single vehicle sold. The bottom line is this: If society is waiting for new technology-enabled vehicles to save the world from transportation-related emissions, the war has already been lost. We need a diverse strategy to address our environmental challenges in a way that ultimately benefits consumers.
What About Non-Light Duty Vehicles?
Most of the electrification policies being considered primarily focus on the light duty vehicle sector. To a degree, I guess this makes sense – in the U.S. there are more than 250 million registered light duty vehicles and, in 2019, they combined to account for 58% of transportation-related greenhouse gas emissions. But what about the approximately 12 million medium- and heavy-duty vehicles that contribute 24% of transportation-related greenhouse gas emissions? It is generally accepted that electrifying these vehicles will be much more challenging than doing so for new LDVs, yet they pack a disproportionate punch with regards to GHG emissions.
If these numbers are accurate, they raise the question: Are current efforts focused on gaining the greatest bang for our emissions-control buck? If light duty vehicles emit 1,085 million metric tons of CO2 equivalent from approximately 250 million vehicles, this equals about 4 metric tons per vehicle. Meanwhile, the 12 million medium and heavy duty vehicles emit 444.4 million metric tons for an average of 37 metric tons per vehicle. How are we going to address this, not in 15 – 20 years when electrified powertrains might make economic sense for these vehicles, but now?
Multi-Pronged Approach is Required
Media headlines and political stump speeches do not like complex messaging – it doesn’t fit the sound byte and you risk losing your audience very quickly. For that simple reason, I understand the short cut messages being pushed upon the population. But when pencil hits paper to structure policy that will redefine the transportation sector forever, it is incumbent upon leaders to tackle the complexity, to evaluate the specific vehicle use cases and develop sustainable and feasible solutions. Not all light, medium and heavy duty vehicles function the same or serve the same purpose and understanding these nuances is critical to crafting a sustainable strategy that will reduce emissions quickly and effectively while preserving the economic value required by consumers. Remember access to reliable and affordable transportation is critical for consumers; as is access to reliable and affordable goods and services that are enabled by the medium and heavy duty sector.
The Fuels Institute is working on a variety of papers that will help inform these deliberations. Within the next nine months, we will publish papers on the following subjects:
* Comparative analysis of life cycle assessments for electric and combustion engine vehicles and their energy sources. This paper will look at the cradle to grave lifecycles of each powertrain system to determine where emissions originate in order to help develop strategies to improve the performance of each. Because both vehicle types will coexist for decades, we must endeavor to improve the environmental footprint of each.
* Assessment of the medium and heavy-duty vehicle market. This is a dynamic sector of the market that is comprised of various vehicle types, use cases and energy needs. By segmenting the sector into its composite parts and providing insight into the size and energy needs of each, this report can help guide pragmatic approaches to emissions reductions.
* Leveraging the lower carbon intensity of biofuels. There is no argument that renewable biofuels present a lower carbon intense liquid fuel option for combustion engines. This paper will seek to quantify this advantage and evaluate the various policies that could be pursued to effectively leverage this positive environmental attribute in a way that benefits the market and consumers.
* Recognizing the potential for combustion engines and liquid fuels. Despite the headlines extolling the death of the combustion engine, it is far from extinct and there are countless ongoing research projects to determine how efficient these engine-liquid fuel systems can become. This project will review these initiatives to highlight what might be possible for lowering emissions from the currently dominant powertrain system so that the market can take advantage of these opportunities.
Addressing Individual Needs is Key to Success
I love Sammy Hagar and I agree that there is only one way to rock and that is with all of your heart and soul. But I believe you can achieve that experience with most any kind of music that appeals to your unique preferences. Similarly, when it comes to reducing emissions from the transportation sector and benefiting consumers, we need all kinds of solutions to appeal to the various vehicle types, use cases and energy needs of the market. Only then will we truly be able to say we are doing something for the future of the environment – otherwise we are taking a short cut that I think is very insufficient. Hopefully, the information the Fuels Institute is seeking to provide can offer some additional insight to guide strategies that will benefit both the environment and the needs of consumers.
BSEE Monitors Gulf of Mexico Oil and Gas Activities in Response to Hurricane Ida, Updated 09/11/202
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-monitors-gulf-of-mexico-oil-and-62
NEW ORLEANS — Bureau of Safety and Environmental Enforcement (BSEE) activated its Hurricane Response Team as Hurricane Ida made its way through the Gulf. The Hurricane Response Team continues to monitor offshore oil and gas operators in the Gulf as they return to platforms and rigs after the storm. The team works with offshore operators and other state and federal agencies until operations return to normal.
Based on data from offshore operator reports submitted as of 11:30 CDT today, personnel are still evacuated from a total of 62 production platforms, 11.07 percent of the 560 manned platforms in the Gulf of Mexico. Production platforms are the structures located offshore from which oil and gas are produced. Unlike drilling rigs, which typically move from location to location, production facilities remain in the same location throughout a project’s duration.
Personnel are still evacuated from 2 rigs (non-dynamically positioned), equivalent to 18.18 percent of the 11 rigs of this type currently operating in the Gulf. Rigs can include several types of offshore drilling facilities including jackup rigs, platform rigs, all submersibles and moored semisubmersibles.
A total of 2 dynamically positioned rigs remain off location. This number represents 13.33 percent of the 15 DP rigs currently operating in the Gulf. Dynamically positioned rigs maintain their location while conducting well operations by using thrusters and propellers. These rigs are not moored to the seafloor; therefore, they can move off location in a relatively short time frame. Personnel remain on-board and return to the location once the storm has passed.
As part of the evacuation process, personnel activate the applicable shut-in procedure, which can frequently be accomplished from a remote location. This involves closing the sub-surface safety valves located below the surface of the ocean floor to prevent the release of oil or gas, effectively shutting in production from wells in the Gulf and protecting the marine and coastal environments. Shutting in oil and gas production is a standard procedure conducted by industry for safety and environmental reasons.
From operator reports, it is estimated that approximately 61.60 percent of the current oil production in the Gulf of Mexico is shut in. BSEE estimates that approximately 60.67 percent of the gas production in the Gulf of Mexico is shut in. The production percentages are calculated using information submitted by offshore operators in daily reports. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day. The shut-in production figures therefore are estimates, which BSEE compares to historical production reports to ensure the estimates follow a logical pattern.
Facilities are currently being inspected. Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back online.
U.S. Gulf Coast oil refiners recovering faster than producers, By Erwin Seba, Reuters.com, September 10, 20216:44 PM CDT
https://www.reuters.com/business/energy/us-gulf-coast-oil-refiners-recovering-faster-than-producers-2021-09-10/
HOUSTON, Sept 10 (Reuters) - Most of the nine Louisiana refineries shut by Hurricane Ida have restarted or were restarting on Friday, nearly two weeks after the powerful storm came ashore, a Reuters survey showed.
Refiners are coming back faster than oil production, a reverse of past storm recoveries. Just three of the nine refineries were completely idled, accounting for about 7% of Gulf Coast refining, compared to shut-ins of two-thirds of oil output.
Valero Energy Corp’s (VLO.N) Maraud refinery on the Mississippi River east of New Orleans was restarting units on Friday, people familiar with the matter told Reuters. Valero also is preparing its St. Charles refinery to restart, the company has said.
Royal Dutch Shell’s (RDSa.L) Norco refinery was receiving limited power on Friday, and is planning to begin restarting in one to two weeks, according to company reports and people close to the company.
PBF Energy’s (PBF.N) Chalmette refinery has restarted some units but has not resumed production, sources told Reuters.
The state's two largest refineries - Marathon Petroleum’s (MPC.N) 578,000 barrel per day (bpd) Garyville and Exxon Mobil Corp's 520,000 bpd Baton Rouge plant - have returned to operation, the companies said on Friday.
Exxon (XOM.N) is operating its two gasoline-producing units at maximum capacity, said people familiar with plant operations. It has received 3 million barrels of crude from the U.S. Strategic Petroleum Reserve (SPR).
The hardest hit refinery, Phillips 66’s (PSX.N) 255,600 bpd Alliance plant in Belle Chasse, faces months of repairs that could rival those needed after 2005’s Hurricane Katrina, sources familiar with the situation said. It was continuing to pump water out of the refinery on Friday, the sources said. Phillips 66 had repaired a broken flood wall that allowed storm waters to enter the plant, a spokesperson said.
Two other refineries: Placid Refining's 75,000-bpd Port Allen refinery and Delek US Holdings' (DK.N) 80,000-bpd plant in Krotz Springs restarted early this week. Placid has received 300,000 barrels of crude oil from the SPR.
“The supply data contained in this ‘Weekly Petroleum Status’ report are based primarily on company submissions for the week ending 7:00 a.m. the preceding Friday. Selected data are released electronically after 10:30 a.m. Eastern Standard Time (EST) each Wednesday.”
“Reporting lag”, my interpretation is that could be part of it. For the week of September 3rd from the final week of August petroleum demand declined 13%, U.S. crude refinery inputs contracted 1.6 mm b/d, and production only dropped 1.5 mm b/d.
Mrs. Smith
U.S. Economic Activity Charts, Issued September 7, 2021, Federal Reserve Bank of Dallas
https://www.dallasfed.org/-/media/Documents/research/econdata/uscharts.pdf
Database of Global Economic Indicators (Real, Price, Trade and Financial), Charts as of September 2021:
https://www.dallasfed.org/institute/dgei
Mrs. Smith
Weekly Petroleum Status Report, Released Sept. 9, 2021, Data for week ending Sept. 3, 2021
Full Report with Graphs/Tables: https://www.eia.gov/petroleum/supply/weekly/pdf/wpsrall.pdf
Data Overview: https://ir.eia.gov/wpsr/overview.pdf
HIGHLIGHTS
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 1.5 million barrels from the previous week. At 423.9 million barrels, U.S. crude oil inventories are about 6% below the five year average for this time of year. Total motor gasoline inventories decreased by 7.2 million barrels last week and are about 4% below the five year average for this time of year. Finished gasoline and blending components inventories both decreased last week. Distillate fuel inventories decreased by 3.1 million barrels last week and are about 12% below the five year average for this time of year. Propane/propylene inventories increased by 0.8 million barrels last week and are about 20% below the five year average for this time of year. Total commercial petroleum inventories decreased by 10.4 million barrels last week.
U.S. crude oil refinery inputs averaged 14.3 million barrels per day during the week ending September 3, 2021 which was 1.6 million barrels per day less than the previous week’s average. Refineries operated at 81.9% of their operable capacity last week. Gasoline production increased last week, averaging 10.1 million barrels per day. Distillate fuel production decreased last week, averaging 4.2 million barrels per day.
U.S. crude oil imports averaged 5.8 million barrels per day last week, decreased by 0.5 million barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.2 million barrels per day, 12.2% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 899,000 barrels per day, and distillate fuel imports averaged 142,000 barrels per day.
Total products supplied over the last four-week period averaged 21.5 million barrels a day, up by 18.8% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.5 million barrels a day, up by 8.9% from the same period last year. Distillate fuel product supplied averaged 4.1 million barrels a day over the past four weeks, up by 11.2% from the same period last year. Jet fuel product supplied was up 65.3% compared with the same four-week period last year.
The West Texas Intermediate crude oil price was $69.34 per barrel on September 3, 2021, $0.50 above last week’s price and $29.65 more than a year ago. The spot price for conventional gasoline in the New York Harbor was $2.339 per gallon, $0.054 more than last week’s price and $1.118 above a year ago. The spot price for ultra-low sulfur diesel fuel in the New York Harbor was $2.157 per gallon, $0.050 above last week’s price and $1.031 over a year ago.
The national average retail regular gasoline price was $3.176 per gallon on September 6, 2021, $0.037 per gallon more than last week’s price and $0.965 over a year ago. The national average retail diesel fuel price was $3.373 per gallon, $0.034 above last week’s price and $0.938 over a year ago.
‘The northern Gulf of Mexico offshore super basin: Reservoirs, source rocks, seals, traps, and successes’
Source: AAPG Bulletin, v. 104, no. 12 (December 2020), pp. 2603–2642, American Association of Petroleum Geologist
AUTHORS
John W. Snedden ~ Institute for Geophysics, The University of Texas at Austin, Austin, Texas; jsnedden@ ig.utexas.edu John W. Snedden is a senior research scientist at the Institute for Geophysics, The University of Texas at Austin. He is director of the Gulf of Mexico Basin Depositional Synthesis project, a consortium dedicated to research on the depositional history of the Gulf of Mexico. Prior to taking his current position, he worked in the oil industry for 25 years, exploring basins around the world. He and William Galloway are authors of the recent book, The Gulf of Mexico Sedimentary Basin: Depositional Evolution and Petroleum Applications (Cambridge University Press, 2019).
Robert C. Cunningham ~ ChargeSearch, Llano, Texas; rcunningham.cs@gmail.com
Robert C. Cunningham is a petroleum systems consultant with a primary focus on analyzing and mapping source properties in conventional and unconventional plays. In his 31 years in the oil industry, he led teams on global source rock prediction and basin modeling and conducted petroleum systems analysis in basins throughout the world.
Jon W. Virdell ~ Institute for Geophysics, The University of Texas at Austin, Austin, Texas; jvirdell@ig.utexas.edu
Jonathan W. Virdell is a project manager at the Institute for Geophysics, The University
of Texas at Austin. He is part of the Gulf of Mexico Basin Depositional Synthesis project research team, contributing his experience in geographic information systems and geophysical data. He holds an A.S. in environmental science and technology from Austin Community College and a B.A. in biology from The University of Texas at Austin.
ABSTRACT
The northern Gulf of Mexico federal offshore area easily qualifies as a super basin based upon estimated petroleum endowment of more than 100 BOE and cumulative production of 60 BOE. Like other super basins, it has multiple petroleum systems and stacked reservoirs. Examination of four key elements of these petroleum systems (reservoirs, source rocks, seals, and traps) yields important insights to the geologic processes that result in such an exceptional habitat for conventional hydrocarbons.
The bulk of hydrocarbon resources in federal offshore waters is in Cenozoic sandstone reservoirs such as the Paleogene Wilcox reservoir of deep-water subsalt areas. Overall, Cenozoic sand- stone reservoirs in both suprasalt and subsalt fields yield the highest flow rates and cumulative production volumes. Notable is the re- cent addition of the deep-water Jurassic Norphlet sandstone play, the newest and second largest by ultimately technically recoverable resources. Overall, Gulf of Mexico reservoirs are diverse, formed in paleoenvironments ranging from aeolian to deep water.
Powering this super basin are three primary marine source rocks centered in the Oxfordian, Tithonian, and Cenomanian–Turonian Stages. These source rock intervals commonly act as top seals, but other Neogene and Mesozoic shales and even carbonate mudstones are also important trap-sealing elements, as proven by analytical work and downhole pressure measurements. The extensive salt distribution and relatively late Cenozoic burial delayed source rock maturation and migration until the culmination of trap formation in many areas.
High rates of Cenozoic deposition on a mobile salt substrate also generated a myriad of salt tectonic structures, ranging from simple diapiric closures and extensional fault traps to complex subsalt configurations such as salt-cored compressional anticlines, salt-cutoff traps, and bucket weld traps. Exploration success in the past 20 yr is a direct result of improved seismic imaging around and below salt, as well as advances in drilling, completing, and producing wells and fields.
INTRODUCTION
Overview
The concept of a “super basin” is relatively new, first coined by Fryklund and Stark (2016), who defined it as a basin having a prolific petroleum system (remaining recoverable reserves >5 BOE; past production >5 BOE), a well-established surface infrastructure, ready access to markets, multiple petroleum systems, and stacked reservoirs.
With an estimated endowment of 112.8 BOE of ultimate technically recoverable resources (UTRR) and cumulative production of 60 BOE (Bureau of Ocean Energy Management, 2017; Duncan et al., 2018), the offshore United States or northern Gulf of Mexico (GOM) Basin easily qualifies (Figure 1). In fact, more than 50% of the estimated UTRR in the United States as a whole are situated in the northern GOM (US Geological Survey, 2005).
Past production exceeding five BOE is another threshold that super basins must exceed according to the definition from Fryklund and Stark (2016). This often requires wells with high flow rates, particularly in deep-water areas where costs of develop- ment and production are extraordinarily high. For example, the top 10 producing wells in the northern GOM by both average production rate (Figure 2A) and cumulative production (Figure 2B) are all located in deep-water areas and are largely relatively young (Pliocene and Miocene) sandstones whose porosity and permeability are high (>20% porosity, a darcy or more of permeability; Hentz et al., 1997; Weimer et al., 1998). Notable exceptions are wells at St. Malo and Chinook that are older Paleogene-age Wilcox reservoirs (Weimer et al., 2016b) that benefit from novel completion and stimulation techniques such as “frac packs” (Mattos et al., 2013).
Other criteria for a super basin are the presence of a well established production infrastructure and ready access to markets for commodities (Fryklund and Stark, 2016). In the northern GOM federal waters (beyond the 5-mi [8-km] state limit), it is estimated that more than 7000 drilling and production platforms have been installed. More than 52,000 wells have been drilled offshore at the time of this writing. Fields have been discovered in both state waters and onshore in trends extending north from the United States–Mexico border to the southern tip of Florida.
The geologic factors that distinguish super basins from other global basins are somewhat less quantitative. Super basins are often described as including multiple source rocks charging numerous stacked reservoirs (Fryklund and Stark, 2016). Despite the prolific GOM Basin hydrocarbon production and remaining potential reserves, few recent papers have attempted to compile, synthesize, and illuminate this super basin’s key success factors in a single document.
The purpose of this paper is to describe in summary fashion the four key elements of the GOM Basin that have powered the enormous hydrocarbon endowment that put this area in the top tier of petroleum habitats. Examples of key reservoirs, source rocks (and maturation windows), seal rocks, and traps are provided. We focus our discussion on regional to basin-wide trends and do not delve into block or prospect-specific controls such as local burial or hydrocarbon charge history or individual salt tectonic structures.
Several super basins have both conventional and unconventional plays, sometimes linked to the same
petroleum system. As described later in this paper, at least two major source rocks (Tithonian centered and Cenomanian–Turonian) are present basin-wide, charg- ing offshore conventional traps but also acting as con- tinuous resources for onshore unconventional plays. Our discussion here, however, is limited to the offshore conventional plays that dominate the current UTRR. The reader is referred to several other publications that describe unconventional plays in the GOM Basin, including Hammes et al. (2011, 2016), Enomoto et al. (2012), Hackley (2012a, b), and Snedden and Galloway (2019).
Geographic Location of Basin, Fields, and Discoveries
The GOM Basin as a whole surrounds and includes a large body of water connected to the Atlantic Ocean via the Straits of Florida. In United States waters, it extends north from the deep abyssal plains in its center to its termination south of the largely buried Paleozoic Ouachita thrust belt and east to the Straits of Florida connection with the Atlantic Ocean.
Hydrocarbon discoveries and continuous resource plays in the northern GOM Basin occur in an arcuate trend (Figure 1). With few exceptions, a dividing line can be drawn between carbonate-dominated, largely onshore Mesozoic fields and discoveries and that of the siliciclastic-prone Cenozoic hydrocarbon habitat. This dashed line coincides with the downdip limit of Mesozoic platform margin reefs, largely pinned by a major increase in accommodation at a deep crustal boundary. Cenozoic systems, by contrast, backed by large sediment influxes sourced by the United States Cordilleran and Laramide tectonic belts, prograded past this line in an attempt to fill this basin center.
Despite continuous exploration of this basin since the discovery of oil at the Spindletop salt dome near the turn of the twentieth century, there remains large white spaces with no current hydrocarbon fields or past discoveries. Some areas are restricted by drilling moratoria, such as the Florida shelf and adjacent deep water. In other areas, deep Cenozoic burial and/or challenges to imaging below the modern salt canopy hampered exploration until recently developed tech- niques like wide-azimuth seismic acquisition were employed (as discussed in later sections).
GEOLOGIC HISTORY
Mesozoic Tectono-Stratigraphic Phases
Comprehensive synthesis of the GOM Basin history, inlightofnewscientificandexplorationinsights,is described in detail in Snedden and Galloway (2019), which we summarize briefly here. The tectono-stratigraphic system encompasses six phases, three each in the Mesozoic and Cenozoic Eras (Figure 3). These phases reflect both the long-term tectonic evolution of the basin and its predecessors, as well as the shorter-term eustatic and climatic processes influencing sedimentation. Although the Cenozoic phases have higher frequency (four phases over 66 m.y.), one can argue for three Mesozoic tectono-stratigraphic phases over 170 m.y. or more since the end of the suturing of Pangea and joining of Laurentia and Gondwana. The three phases that cover the post- Ouachita–Marathon–Appalachian orogeny to the end of the Cretaceous (299–66 Ma) are the postorogenic successor basin-fill and rifting phase, the MiddleMesozoic drift and cooling phase, and the Late Mesozoic local tectonic and crustal heating phase.
We regard the first phase as a predecessor to formation of the GOM Basin, but it is worthwhile to discuss some of the tectonic and stratigraphic elements that persisted into the Middle Mesozoic drift and cooling phase or even later. Galloway (2008) has argued that the GOM Basin initiated with deposition of the Louann Salt, the first stratigraphic unit that spans the nascent GOM. Salt deposition was probably underway at 170 Ma, at the start of the drift and cooling phase (Peel, 2019; Snedden et al., 2019). New plate tectonic models suggest that accelerated opening of the Gulf began as an intrusive phase of oceanic crust generation below the accumulating mass of evaporites and later extrusive separation of salt bodies between the northern and southern GOM (Norton et al., 2016).
During the initial stages of basin opening (Middle Mesozoic and drift and cooling phase), arid climate conditions persisted, and a broad belt of dryland de- position, including a prominent aeolian sand sea (erg), developed in the eastern part of the northern GOM (Mancini et al., 1985; Snedden and Galloway, 2019). The largest Mesozoic reservoir by UTRR in federal waters (Figure 4), the Norphlet play fairway now extends from onshore areas to state waters to the Mississippi Canyon (MC) and Desoto Canyon (DC) protraction blocks in deep water. Smaller dryland systems including aeolian dunes are present in Cuba (San Cayetano Formation) (Haczewski, 1976) and in Mexico where the Bacab Sandstone produces oil intheEk,Balam,andotherfields(Cantu ´-Chapa, 2009; Snedden et al., 2020). Local restrictions in deep bottom water circulation allowed preservation of organics in both the Oxfordian and Tithonian, forming important source rocks (Hood et al., 2002; Cun- ningham et al., 2016).
The late Mesozoic local tectonic and crustal heating phase followed the end of seafloor spreading in the GOM. The basin at this point reached its present size, and, combined with favorable climatic conditions, carbonate systems transitioned from local grainstone shoals and thrombolite buildups to platform margin and shelf interior reefs and associated grainstone aprons (Mancini et al., 2004). Siliciclastics from the older source terranes like the Appalachians were largely trapped behind the reef margins, reducing turbidity that would have otherwise limited the growth of frame-building corals, sponges, and rudistid bivalves. This reached an acme in the middle Cretaceous (Albian) as reefal systems delineated the basin margin but also surrounded isolated platforms in Mexico. Small but still economically important carbonate reservoirs of the Cretaceous Andrew Forma- tion and James Limestone (Kosters et al., 1989; Petty, 1999) are part of this phase of high carbonate productivity. Igneous activity and uplifts locally developed with igneous intrusive-cored bathymetric highs forming the site of carbonate buildups (Ewing, 2009).
An abrupt termination of reefal carbonate deposition at the end of the Albian has been attributed to several causes, including increased water turbidity with the Tuscaloosa sandstone influx (Snedden et al., 2016), uplift in the Mississippi Embayment (Cox and Van Arsdale, 2002), and the cumulative effects of a series of oceanic anoxic events (OAEs) (Phelps et al., 2015). The OAE2 is associated with development of the Cenomanian–Turonian source rock (Eagle Ford equivalent), although regional conditions such as strong outflow bottom water flow caused a temporal offset from the global event (Lowery et al., 2017). Following the major sand volume influx that built a large Cenomanian–Turonian (Tuscaloosa) submarine fan present in deep water, global sea-level rise flooded the basin. As a result, deep shelf and basinal carbonates including chalks dominated the latest Mesozoic.
The end of the late Mesozoic local tectonic and cooling phase, and the Mesozoic as a whole, was ushered in by the Chicxulub impact event at 66 Ma, which greatly altered the paleobathymetry and land surface of the GOM (Denne et al., 2013; Sanford et al., 2016; Lowery, et al. 2018). It also, to some degree, set up the basin configuration that the Cenozoic tectono-stratigraphic phases modified by sediment input from the newly emerged Laramide highlands and rejuvenated Appalachians mountains (Boettcher and Milliken, 1994; Galloway et al., 2011; Blum and Pecha, 2014; Snedden et al., 2018).
Cenozoic Tectono-Stratigraphic Phases
Much like the Mesozoic fill, the Cenozoic fill of the GOM can be subdivided into three tectono-stratigraphic phases. Unlike Mesozoic phases, they do not reflect processes of basin opening and evolution; rather, they record a combination of influences driven by convergence along the western North American plate margin,
by intraplate tectonism, by evolving patterns of continental climate and consequent drainage basin evolution and runoff, and finally by global climate change and resultant glacio-eustasy. Snedden and Galloway (2019) refer to these as the Paleogene Laramide phase, the middle Cenozoic geothermal phase, and the Neogene tectono-climatic phase.
Paleogene Laramide Phase
The structural architecture of the northern GOM at the start of the Cenozoic reflected the far field but still prominent effects of the Chicxulub impact event (Denne et al., 2013). It also inherited the shallow shelf, relict carbonate platform margins, and deep basin configuration of the preceding Cretaceous Period. Laramide deformation in the western United States progressed from north to south, generating a voluminous increase in siliciclastics that quickly filled in Rocky Mountain Basin accommodation. Large trunk rivers flowed toward the northern GOM Basin during a relatively humid climatic phase with vast swamps and wet coastal plains developed in the Paleocene and Eocene (DeCells, 2004; Snedden and Galloway, 2019)
The northern Gulf Paleogene record includes three expanded depositional supersequences: (1) lower Wilcox, (2) middle Wilcox, and (3) upper Wilcox (Galloway et al., 2011). These three major siliciclastic successions include reservoirs formed in the full paleoenvironmental spectrum from bed- load–dominated fluvial to abyssal plain fans. Submarine fan run-out lengths in the 1000-km range scaled to the length of the large extrabasinal rivers extending back to the northern Rockies (Snedden et al., 2018). Exploration followed the Wilcox reservoirs from shallow fields onshore to deep-water fields below the salt canopy, transitioning reservoir styles from fluvial to delta or shore zone to slope and submarine fan and commodity type (water, coal, gas, and oil) along the way to the deep basin. The bulk of sedimentation was in the western half of the northern GOM, linked to several continental scale rivers draining the emerging Rockies. Deposited onto salt on its downdip extent, the immense sediment load drove salt evacuation and the seaward and upward migration of the allochthonous salt canopy.
Massive extensional systems generated landward are partially compensated by folding and contraction downdip, with localized shortening and folding of salt. Burial of Mesozoic source rocks initiated hydrocarbon maturation and migration except below the paleo-canopy where heat flow was much reduced.
Middle Cenozoic Geothermal Phase
The middle Cenozoic geothermal phase is a 23-m.y. record of tectonic reorganization of western North America, as new crustal uplifts and volcanic centers generated new source terranes. Sediment load in the main trunk streams was impacted by volcanic eruptions, particularly in the southwestern sectors where the paleo Rio Grande and other rivers were choked with volcanic ash. The major depositional influx during deposition of the Oligocene Frio supersequence filled accommodation space onshore in the FrioVicksburg fault zone, which in combination with more arid climates in the Rockies, constrained sediment bypass to the deep basin. Eastern parts of the basin continued to be relatively sediment starved, a pattern initiated in the Paleogene. Elsewhere, crustal tilting and elevation of the basin fringe amplified normal basinward displacement of both the sediment prism and mobilized salt (Galloway et al., 2011; Snedden and Galloway, 2019).
Late Neogene Tectono-Climatic Phase
The final 15 m.y. of depositional history in the northern GOM records a relative decline in siliciclastic sediment
supply from inland source terranes, but it is still notable in size and extent. Rejuvenation of older Appalachian Mountains (caused by deep crustal processes) led to a shift of sedimentation to the eastern areas, culminating in two basin-scale submarine fans as found in the MC, Walker Ridge, and Lund protraction blocks (Galloway, 2008). These form amalgamated reservoir sequences above the salt canopy in load-induced minibasins.
By the Pliocene, competing rivers from the Western Interior and Appalachians first progressively coalesced into three paleo-rivers and then finally into one major river, the forerunner of the modern Mississippi system. Pleistocene glaciation fed immense volumes of sediment to this river, culminating in the Mississippi Fan, which today covers nearly half of the northern GOM Basin (Galloway et al., 2011). Salt-defined minibasins in the western and central deep-water areas continued to fill throughout the Pliocene–Pleistocene and spilled sands basinward and further south past the Sigsbee margin where the allochthonous salt canopy meets the modern seabed (Snedden and Galloway, 2019).
The net result of 66 m.y. of siliciclastic deposition is a super basin whose floor is almost completely covered by long and broad submarine fans of various ages (Figure 5). This in turn reflects the dominance of large river systems fed by an evolving tectonic landscape, favorable climatic conditions, and time-averaged close proximity of delta point sources to the slope and basin (Sweet and Blum, 2016; Snedden et al., 2018). Wholesale shelf edge bypass, with focused sand transport onto and across the abyssal plain, was a major feature of both greenhouse (Paleocene–early Eocene) and icehouse (Miocene–Pleistocene) worlds (Sweet and Blum, 2011). These basin-scale submarine fans deposited thick successions of stacked reservoirs that when filled by migration of hydrocarbons into salt tectonic traps sealed by deep-water mudstones, they support field sizes ranging up to giant class (Weimer et al., 2017c).
RESERVOIRS
As mentioned previously, the presence of stacked reservoirs is one characteristic of super basins.
Conventional reservoirs provide both the storage capacity (often expressed as porous rock volume) and necessary flow capacity (indicated by in situ permeability). Ade- quate net porous and permeable rock is a prerequisite for commercial development of discoveries. In the GOM, both sandstone and carbonate reservoirs were deposited in a variety of sedimentary settings from nonmarine to deep marine (Ewing and Galloway, 2019).
Virtually every stratigraphic interval above the Louann Salt contains reservoirs that in some part of the greater GOM Basin harbor hydrocarbons, either conventional sandstone or carbonate types or unconventional source rock reservoirs (Snedden and Galloway, 2019). Commercial development of the unconventional resources is limited to onshore areas where the cost of production infrastructure is far lower than in the offshore transition zone, shelf, or deep water.
In United States federal offshore waters, however, the vast majority of fields and discoveries are developed in Cenozoic sandstone reservoirs (Figure 4). These reservoirs produce at the highest average rates and historically have the largest cumulative production (Figure 2A, B). This is because of the high porosity and permeability of these relatively young, uncompacted, and diagenetically unaltered quartzose sandstones (Hentz et al., 1997; Marchand et al., 2015).
Of the Cenozoic intervals, all reservoirs are sandstones ranging in age from Paleocene to Pleisto- cene. The Paleogene (Eocene and Paleocene) Wilcox now hosts the largest UTRR (Bureau of Ocean Energy Management, 2017; Figure 4). The Wilcox deep-water play was ushered in by the drilling of the BAHA II well and subsequent oil discoveries (Zarra, 2007). Success of post-2000 subsalt ex- ploration is evident in the large number of fields and discoveries (26 total). Younger-age reservoirs within the Pliocene and Pleistocene were drilled earlier in the shallower postsalt section, making effective use of seismic facies and amplitudes and regional mapping (Prather et al., 1998). In the eastern GOM, middle and upper Miocene sandstones are the primary reservoirs in giant and supergiant fields like Thunderhorse (Henry et al., 2017; Weimer et al., 2017b, c)
Emerging plays in the inboard subsalt areas of Green Canyon (GC) and Garden Banks (GB) protraction blocks include the middle and lower Miocene reservoirs are found in Tahiti, Holstein Deep, and Vito fields and discoveries (Thacher et al., 2013; Figure 4). The recent Paleogene discovery at Anchor also is located in this same general area (Zarra et al., 2019). Earlier exploration in outboard areas, where the salt canopy is less complex, discovered oil in middle Miocene reservoirs such as in the Atlantis field of the GC protraction block (Mander et al., 2012).
The few Mesozoic exceptions to the Cenozoic dominance of northern GOM offshore production include the Middle Jurassic (Oxfordian) Norphlet Formation, the Cretaceous (Aptian) James Lime- stone, and Cretaceous (Albian) Andrew Formation (Figure 4). The Norphlet Formation is the largest and newest Mesozoic reservoir and is already one of the largest overall. It differs from most northern GOM Cenozoic producing reservoirs in several ways.
First, the sandstones are thought to have formed in a dryland depositional system, which differs from all other reservoirs in present-day deep-water settings of the northern GOM (Figure 6). Many cores from deep-water Norphlet wells show repetitive successions of quartz-rich sandstones with high-angle cross-beds typical of large aeolian dunes (Godo, 2019; Figure 7A). Cross-beds are consistently unimodal with interpreted paleowinds converging around the western end of the Middle Ground arch where the Norphlet thicknesses can exceed 1000 ft (305 m) (Hunt et al., 2017). Our reconstructions depict a long phase of arid climate and strong winds sweeping loose terrigenous sediment off of large exposed continental land masses of the North American and African plates, which were in close proximity prior to the initiation of sea-floor spreading in the Late Jurassic (Snedden and Galloway, 2019). Sandstones accumulated in salt-defined depocenters that varied from aeolian dune to ephemeral stream fluvial deposits (Godo, 2019; Figure 6). The best sandstones are in the aeolian dune deposits because of mitigation of burial diagenesis by the presence of grain-rimming chlorite that resisted quartz cementation in these deeply buried reservoirs (Godo, 2017).
Second, many of the Norphlet oil discoveries reflect raft tectonics, as blocks of Smackover and Norphlet glided down a paleoslope to the west and south from the Middle Ground arch (Pilcher et al., 2014). Thus, reconstructions of this important de- positional system require both restoration back to a pre–sea-floor spreading state as well as correc- tions for raft translation and rotation (Snedden and Galloway, 2019).
Shell’s initial discovery was made at the Shiloh prospect (DC 269-1; see location 7 in the Appendix) in 2003, but a 10-yr campaign of acreage bidding and leasing, exploration drilling, and appraisal even- tually led to the first Norphlet deep-water develop- ment at Appomattox (MC 392 and adjacent blocks; Godo, 2017) that started production in May 2019. Subsequent deep-water Norphlet discoveries at Rydberg (2014), Fort Sumter (2016), and Ballymore (2017) confirm the importance of this play (loca- tions 9, 31, and 27 in Figure 6, respectively, and location information in the Appendix).
The remainder of the Mesozoic UTRR is found in relatively small fields and discoveries in carbonate reservoirs of the shallow eastern GOM shelf. The Andrew and James are carbonate reservoirs, extensions of onshore Mesozoic production to shallow offshore areas (Petty, 1999)
Earlier exploration phases onshore and in shallow waters did cover the full spectrum of siliciclastic reservoir types from fluvial to shore zone, deltaic, and shelf (see summary in Snedden and Galloway, 2019). Since the 1980s, interest shifted to present-day deep water and below the extensive salt canopy (Figure 5). Cenozoic reservoirs with significant remaining undiscovered re- sources can be found in the Paleogene and Neogene section with reservoir paleoenvironments ranging from upper slope confined channels to lower slope aprons to abyssal plain submarine fans (Figure 7B–D).
In the Cenozoic are a wide variety of reservoir depositional styles (Figure 7). Important examples include deposits of high-density turbidities, with char- acteristic trough cross-bedding (tractional trough) indicating tractional flows in the Wilcox play of the Alaminos Canyon, Keathley Canyon, and southern Walker Ridge protraction blocks (Figure 7B). This bedding type and massive Bouma Ta beds form some of the best reservoirs with high porosity (15%–23%), permeability (10–100 md), and low silt (<20%–30%) and clay (<5%) content (Marchand et al., 2015).
Miocene reservoirs show a range of reservoir types from confined channel fills of the paleo upper slope to distributive lower slope systems and abyssal plain fans (Snedden and Galloway, 2019). At the Thunderhorse field in the MC protraction block, thick amalgamated submarine fan deposits are dominated by massive Bouma beds with local scouring and avulsions as indicated by mud clast–rich zones (Figure 7C). Directional informa- tion from image logs shows broadly unimodal flows entering the salt-defined Boarshead basin (Henry et al., 2017).
Pliocene–Pleistocene deep-water sandstones deposited in minibasins adjacent to salt diapirs and/or above the allochthonous salt canopy represented the first phase of northern GOM deep-water exploration. Reservoir styles ranged from highly confined channels with massive Ta beds and scours (Figure 7D; Diana field in Sullivan et al., 2004), Ta-dominated channel terminus submarine fans (e.g., Mars Field in Meckel et al., 2002), and channel–levee systems (e.g., Genesis field in Sweet and Sumpter, 2007).
Reservoir Summary
As mentioned earlier, one criterion for a super basin is the presence of multiple, often stacked or amalgamated reservoirs that facilitate discovery and develop- ment and ensure alternative reservoirs in the case of stratigraphic pinch-outs, fault-outs, and erosion. The fields and discoveries of the greater GOM offer a wide diversity of reservoir types ranging from dryland aeo- lian dune sandstones of the Norphlet to deep-water sediment gravity flow deposits (Figure 7). For further details on the stratigraphic occurrence, areal distribution, and characteristics of these reservoirs, the reader is directed to Snedden and Galloway (2019).
SOURCE ROCKS
Most super basins are the habitat for two or more rich source rock intervals (Sternbach, 2020). Powering the northern GOM Super Basin are three primary marine source rocks centered in the Oxfordian, Tithonian, and Cenomanian–Turonian Stages. Minor deltaic to marine sources have been noted within the Paleocene–Eocene Epochs (Wenger et al., 1994; Hood et al., 2002; Ferworn et al., 2003), as well as other lean marine sources in other intervals, including the Aptian and Albian (Comet, 1992; Figure 8).
The regional extent of petroleum systems charged by these three primary source rocks and Cenozoic terrestrial-dominated shales is displayed in Figure 9. Through geochemical studies of petroleum recovered from reservoirs, surface seeps, and the source rocks themselves, the three primary intervals are proven to have generated large volumes of hydrocarbons both nshore and offshore as conventional and uncon- ventional resources. The Upper Jurassic and mid-Cretaceous sources are synchronous with those in other circum-Atlantic, Arctic, and Tethyan Super Basins because of similar tectonic, eustatic, and climatic drivers following post-Pangaea breakup. Common associations are with restricted rift basins and global OAEs that enhanced and preserved or- ganic matter (Figure 8). In the northern GOM, these primary sources are widespread (Figure 9) but occur in temporally discrete intervals. We summarize Mesozoic source rocks in ascending age order below.
Oxfordian-Centered Source Rocks
Exploration in the onshore salt basins pointed to the Oxfordian Smackover Formation as a source for carbonate-sourced oils in northern GOM (Oehler, 1984; Sassen et al., 1987; Sassen, 1988, 1990; Claypool and Mancini, 1989; Wenger et al., 1994). This source interval was deposited as the GOM transitioned from shallow Louann Salt pan to increasingly deeper-marine conditions. Discoveries in the northern GOM shelf and Norphlet deep-water play of the eastern GOM have also been linked to the Oxfordian source, stratigraphically positioned in the middle Smackover member (Godo, 2019). The distinctive geochemical signature of oils from this source identifies a separate GOM petroleum system (Wenger et al., 1994; Hood et al., 2002; Ferworn et al., 2003).
The quality and stratigraphic variability of the Oxfordian source in the deep-water GOM, the habitat for discovered mean UTRR more than 5 BOE (Bureau of Ocean Energy Management, 2017; Figure 4), is illuminated by detailed geochemical analyses undertaken within the Petersburg well (DC 529-1; location 10 in Figure 9 and the Appendix). The Smackover here has three members or lithologic units, namely, an upper limestone, middle marl, and lower limestone that correspond approximately to three Smackover Formation members of onshore Alabama (Mancini et al., 1992; Godo, 2019). The middle-laminated marl and the upper section of the lower limestone have the highest overall total organic car- bon (TOC) content, distributed across a series of thin beds with documented maximums approaching 3%, uncorrected for thermal maturity (Figure 10; Godo, 2019). Gross thickness of this middle Smackover source interval in deep-water wells is in the 800–1000-ft (244–305-m) range. Kerogen is predominately oil- prone marine, type II to IIS, as determined from hy- drogen index (HI) values of 300–500 mg HC/g TOC in richer, less mature samples, pseudo-Van Krevelen diagrams, and hydrocarbon potential versus TOC plots (Smith, 2018). Well rotary cores in the lower part of the lower limestone member display algal laminites to microbialite growth structures with a lower overall average TOC compared to the middle marl (Godo, 2019). Thermal maturity indicators such as the temperature at which the maximum rate of hydro- carbon generation occurs in a kerogen sample during pyrolysis analysis (Tmax) and vitrinite reflectance show the Smackover source rocks are in the oil window over much of the deep-water play area leading to gen- eration of light oil (Smith, 2018; Godo, 2019). In shallower waters where deep crustal derived heat flow is considerably higher, reservoired oils have cracked to dry gas with associated H2S and CO2 (Mankiewicz et al., 2009).
Upper Oxfordian Smackover source rocks have been linked to seeps and shows over a large area of the basin (Hood et al., 2002; Pepper, 2016) and to the giant oil field on production at Appomattox and numerous other discoveries being considered for development in the MC and DC protraction blocks (Smith, 2018; Godo, 2019).
Tithonian-Centered Source Rocks
Tithonian-centered source rocks, referring to zones of organic enrichment within the Cotton Valley–Bossier (CVB) and Haynesville–Buckner (HVB) su- persequences (Figure 11), were recognized early on from seep and reservoired oil analyses in the northern GOM (Figure 9; Comet et al., 1993; Wenger et al., 1994; Cole et al., 1999, 2001; Hood et al., 2002; Ferworn et al., 2003). Biomarker and other geochemical analyses used in these studies demonstrated that the Tithonian-centered petroleum system was generated from clearly different, variably more marly or more siliciclastic-rich source rocks and thus separate from the Oxfordian. Tithonian-centered calcareous to marly source rocks have also been found to have charged fields in the Mexican GOM from the Golden Lane to the Campeche (Gonza ´les-Garcia and Holgu ´in- Quiñones, 1992; Yurewicz et al., 1997; Guzman-Vega, 2000; Santamaria Orozco, 2000; Guzma ´n-Vega et al., 2001; Guzman-Vega and Mello, 2001; Magoon et al., 2001;Holgu ´in-Quiñonesetal.,2005;deLourdesClara Valde ´ s et al., 2009) and the Varadero heavy oil field in Cuba (Schenk, 2008).
Despite the voluminous geochemical evidence of a Tithonian-centered source in deep offshore areas, there was remarkably little published calibration until quite recently. With the growing body of well-log data in the Mesozoic (Weimer et al., 2016a, 2017b), acquired through drilling of the deep-water Wilcox and Norphlet plays, Cunningham et al. (2016) employed D log R, a petrophysical approach using logs calibrated against TOC measurements from sidewall cores and cuttings, to evaluate variation in organic enrichment in Tithonian shales in deep-water areas of the northern GOM. These variations were compared to oil family and source lithofacies interpretations based on reservoired oil and seafloor seeps using an industry proprietary database (GeoMark Research Ltd., 2016, J. Zumberge, personal communication). A key calibration well is the Norton prospect (GB 754-1; Figure 11, location 18 in Figure 9 and the Ap- pendix). Although Norton and the correlative well Wrigley (Ewing Bank [EW] 922-1; location 17 in Figure 9 and the Appendix) are salt raft or carapace penetrations (for definitions, see glossary in Snedden and Galloway, 2019), biostratigraphy suggests strati- graphic condensation did not occur until later in the salt structure’s history and the Upper Jurassic is relatively complete. The Wrigley interval was overturned by salt later in its history (Cunningham et al., 2016). Both wells show the log-derived TOC profile increasing upward from the top HVB surface to the CVB midpoint with values exceeding 10% TOC (log and sample derived) and then declining through the upper CVB and through the overlying Cotton Valley–Knowles interval (Figure 11). They also show net interval thicknesses >300 ft (>91 m) with organic enrichment of more than 5% TOC (log derived), indicating excellent source quality and strong oxygen deficiency in the CVB depositional environment. Other wells extend the observation of organic enrichment more than 5% TOC (log and sample derived) in the CVB across the central GOM to the east (Figures 9, 11).
Given the similar log patterns and levels of organic enrichment at Norton, Wrigley, and other wells (Cunningham et al., 2016), anoxia is suggested to have existed broadly during Tithonian source deposition as the developing GOM ocean basin deepened and became more restricted during drift and thermal cooling. The deep basin remained starved and density stratified through the Tithonian and into the Berriasian (Cunningham et al., 2016). Fur- thermore, organic extracts from Upper Jurassic samples of the Norton show high levels of the biomarker bisnorhopane (Jarvie et al., 2004), which is enriched in source rocks deposited under anoxic conditions (Peters et al., 2007). The organic facies of the Tithonian source is type II to IIS marine oil prone, with HI values in richer, less mature samples ranging from 500 to 650 mg HC/g TOC (Jarvie et al., 2004; Peters et al., 2007). Tithonian organic enrichment in the Campeche Sound in Mexico can range even higher above 20% TOC and 700 mg HC/g TOC with the type IIs kerogen rich in sulfur (Santamaria Orozco, 2000). Sulfur content of Tithonian-sourced oils in northern GOM varies spa- tially, ranging from <0.5% in more clay-rich lithofacies to almost 4% in more carbonate-rich lithofacies, and generally decreases to the west because of the increasing influence of the deep-water Cotton Valley clastic apron (Cunningham et al., 2016). The gross thickness of the Tithonian source averages 700 ft (213 m) in both the northern and southern GOM. Thermal maturity of the Tithonian source grades progressively from dry gas along the outer shelf and upper slope to wet gas and condensate in the midslope to oil over the broad expanse of the lower slope in the northern GOM (Weimer et al., 2016a).
The Tithonian-centered source rocks also extend to onshore areas where the Bossier Shale and Haynesville Shale (or marl) are important unconven- tional (source rock) plays (Cicero et al., 2010; Hammes et al., 2011). In offshore areas, Tithonian- centered sources are particularly important in the northern United States GOM and over the giant field province of the Akal–La Reforma trend in Mexico (Guzman-Vega and Mello, 1999; de Lourdes Clara Valde ´ s et al., 2009). Based on the spatial agreement with the Tithonian-centered oil family composed of reservoired oils and seeps, a large part of the 22 BOE UTRRs estimated for the Wilcox subsalt play in the deep-water GOM (Figures 4, 9) is thought to be derived from the Tithonian-centered source rock.
Cenomanian–Turonian-Centered Source Rocks
Cenomanian–Turonian Eagle Ford–Tuscaloosa (EFT) supersequence mudstones and other Cretaceous shales are well-documented hydrocarbon source rocks for onshore unconventional plays (Hentz and Ruppel, 2011; Hull et al., 2012; Hammes et al., 2016; Zumberge et al., 2016) and for the charge of con- ventional plays in the offshore (Hood et al., 2002; Ferworn et al., 2003). Many of the zones of enriched and preserved organic matter in this time span are linked to oceanographic conditions associated with major carbon isotope–constrained OAEs (Figure 8). The OAEs are geologically brief (<1 m.y.) epi- sodes of oxygen-depleted conditions in the global ocean that resulted from profound perturbations in the carbon cycle. They were originally defined as intervals of globally synchronous black shale deposi- tion (Schlanger and Jenykns, 1976), but subsequent work has shown that individual black shales are often diachronous (e.g., Tsikos et al., 2004a, b; Lowery et al., 2017), and OAEs are best defined by their positive carbon isotope excursion (Jenkyns, 2010). The OAEs are driven by a net increase in nutrients in the global ocean and reduced circulation, although the speculation on the causes ranges from continental weathering, volcanism, global warming trends, to globally high sea-level conditions. Early work suggested that source rocks deposited globally during Cretaceous OAEs and in Jurassic anoxic basins could be responsible for up to 50% of the global hydro- carbon endowment (Klemme and Ulmishek, 1991).
In the offshore northern GOM Basin, source en- richment in the Cretaceous is most clearly associated with OAE2 at the Cenomanian–Turonian boundary (Lowery et al., 2017; Figure 8), although pulses of organic enrichment also occur during Aptian–Albian OAEs. The GOM stratigraphic record does not align particularly well with the documented global sea-level highstand and organic enrichment of OAE2 at the Cenomanian–Turonian boundary. The highest organic content within the onshore unconventional Eagle Ford and Tuscaloosa marine shale plays occurs somewhat earlier and later than the OAE2 isotopic excursion, respectively (Phelps et al., 2015; Lowery et al., 2017). It is believed that the timing of anoxia, productivity, and organic enrichment varies locally because of interaction of the basin with circulation outflow events from the adjacent Western Interior seaway and sea-level rise and intensification of the oxygen minimum zone (Lowery et al., 2017).
Organic enrichment within the offshore Cenomanian–Turonian section can be quite high, with documented TOC values ranging more than 7% at Norton (GB 754-1; Figure 12) and more than 4% at Cheyenne (Lloyd 399-1; location 23 in Figure 9 and the Appendix). Type II marine kerogen is indicated by HI values ranging from 400 to almost 600 mg HC/g TOC at both wells. The thickness of the richest interval in the EFT, presumably spanning the Cenomanian–Turonian boundary, is approximately 100 ft (~31 m). However, dilution of the source by voluminous siliciclastic influx by the Tuscaloosa deep-water system (Snedden et al., 2016; Lowery et al., 2017) can reduce TOC in the submarine fan axes in the central GOM. The Cenomanian–Turonian source is thought to be most important in charging or contributing to charge in the Wilcox reservoirs of the northern Alaminos Canyon, EW, GB, and GC protraction blocks, and shelfal areas, where oil quality may be improved by mixing with higher-sulfur Tithonian-sourced oils (Figure 9; Eikrem et al., 2010).
Other Lower Cretaceous source rocks are known in the onshore and offshore northern GOM and are typically associated with other marly to shaley OAE intervals. They occur within the Albian Mesilla Valley Shale and Boracho Formations on the Comanche shelf in Texas in association with OAE 1d and c, respectively (Scott et al., 2020; Figure 8), the Albian Glen Rose and Sunniland Formations in Texas and Florida, respectively, in association with OAE 1b (Palacas et al., 1984; Sun and Forkner, 2019), the Aptian–Albian Bexar Shale and Pine Island Shale Members of the Pearsall Formation in South Texas in association with OAE 1b and a (Hackley et al., 2009; Hull, 2011; Hackley, 2012b; Hull et al., 2012), and within several Albian-Berriasian intervals observed in Deep Sea Drilling Project boreholes in the Straits of Florida (Katz, 1984; Cole et al., 1999). However, although these occurrences may be rich, they are believed to be more geographically restricted (Enomoto et al., 2012; Hackley, 2012b; Swanson et al., 2013a; Merrill, 2016).
Critical Moment of Source Rock Maturation and Migration
Source richness, distribution, and maturity are just some of the necessary components of an economically valuable petroleum system. An equally relevant process in all super basins is how the critical moment
of generation and migration of hydrocarbons relates to the earlier phases of reservoir–seal pair deposition and trap development (Sternbach, 2020). The role of the allochthonous salt canopy in delaying source rock maturation in the deep-water GOM is an under-appreciated yet critical factor in allowing this basin to be the habitat of such a large hydrocarbon endowment (Ewing, 2016; Figure 13). Oil and gas maturation windows are relatively shallow in onshore basins where continental crust heat flow is high and widely separated diapirs only locally influence maturation processes. Thus, at present, most of the lower Mesozoic source rocks are generating gas in areas like East Texas. This pattern continues to the shallow-water offshore areas where both heat flow decreases marginally but the absence of salt caused by loading and evacuation is still a concern. However, in the area of the allochthonous salt canopy, the nearly continuous salt body transfers heat away from the subsalt areas, effectively deepening the oil and gas windows (Figure 13). This process is accompanied here by reduced heat flow on transitional and oceanic crust, cooler seabed temperatures, and later burial by Cenozoic strata (Husson et al., 2008). The net result is a delay in maturation and primary migration so that Mesozoic source rocks remained viable hydrocarbon generators longer than without a salt canopy (Ewing and Galloway, 2019). Salt tectonics in the deep-water areas continued to nearly present day (Hudec et al., 2013) enhancing cross-stratal vertical migration (Hood et al., 2002) and later trap development and filling, which has significantly increased the overall number of economically attractive hydrocarbon accumulations.
Seal Rocks
Effective seal rocks are also a critical component of petroleum-rich super basins. Seal rocks, which in the GOM Basin vary from shales to carbonate mudstones to evaporites, trap and retain large columns of oil and gas. Competent seals limit significant loss of hydrocarbons caused by capillary leakage, maintaining large hydrocarbon columns over geologic time frames, as evidenced in many large accumulations in the northern GOM migrating from source rocks as old as the Oxfordian (Jurassic) as described in the preceding section.
For the purpose of this discussion, we focus on the geologic factors inherent to the GOM that limit capillary leakage through the top seal. We specifically exclude fault-dependent traps in which sealing along faults results from development of fault gouge, continuous shale smears, and zones of cataclasis (deformation bands), which are controlled by local deformation and other prospect-specific factors.
Mechanical failure of seal rocks is known to oc- cur in situations in which fluid pressures within the reservoir exceed a critical threshold (fracture or lithostatic gradient), causing a major loss of mobile hydrocarbons and leaving a smaller amount of live (moveable) oil or just residual oil. Although this does occur in the GOM Basin, it is not a pervasive risk element, as evidenced by the large GOM hydrocarbon endowment. In addition, in exploration of northern GOM minibasins above salt, where steep dips and rapid burial occur, subsurface pressures can exceed the minimum principal stress and leakage occurs to the surface until pressures fall below the threshold preserving commercial hydrocarbon columns in the case of Popeye and Genesis fields in GC (Seldon and Flemings, 2005).
Despite the abundant discovered resources in the basin, relatively few published studies have specifically analyzed the capillary seal rocks that trap hydrocarbons here. Seal rock integrity can be evaluated in
several ways. First, experimental work on cuttings and core samples is conducted to establish the distribution of pore-throat sizes, often with a nonwetting fluid such as mercury. Second, preproduction pressure data (e.g., modular formation dynamics tester! [MDT; Schlumberger] or reservoir characterization instrument! [RCI; Baker Hughes]) from the field or discovery provide an indication of the seal competency because offsets in fluid pressure mark an effective barrier to fluid pressure communication over geologic timescales. We discuss the evidence from both approaches in the GOM below.
Experimental Analyses on Northern Gulf of Mexico Basin Seals
Capillary or membrane seals trap hydrocarbons in structural closures or along bounding faults (Downey, 1984). Column height is controlled by the pore system of the sealing lithology because the largest pore throat serves as the weak point allowing leakage until buoyancy forces equalize the opposing capillary forces (Jennings, 1987). Other influencing factors are the interfacial tension between various fluids, oil, water, gas, and CO2 (Schowalter, 1979). Pore systems in shales and carbonate mudstones are measured using mercury (Hg) injection at high pressure (MICP), yielding important parameters such as the approximate entry pressure and pore-size distribution, with corrections for closure and conversion to hydrocarbon–water systems and adjustments for hydrocarbon composition, temperature, and pres- sure (Wardlaw and Taylor, 1976).
Using a combination of MICP, compositional, and petrophysical analyses over several GOM Miocene deep-water shales, Dawson and Almon (2005) identified six end-member seal types (Table 1). The six identified type shales (mudstones and claystones) range from seal type 5 silty laminated shale (including microporous quartz) with the lowest entry pressure (MICP at 10% Hg saturation) to seal type 1 carbonaceous shales with low silt content and highest entry pressures.
Dawson and Almon (2005) also estimated expected hydrocarbon column heights for the Miocene deep-water seals using parameters conditions known to exist at the depth from which each sample was collected, including subsurface temperatures, water and hydrocarbon density, and grain size (Table 1). Corresponding median (50% probability, P50) column heights ranged from 1265 ft (386 m) for seal type 1 to 160 ft (18 m) for seal type 5. All samples were derived from depths greater than 10,000 ft (>3049 m). Compaction was thus well advanced, and differences are thought to be caused by changes in mudstone composition, silt content, and fabric (Dawson and Almon, 2005)
Dawson and Almon (2005) also related seal characteristics to the sequence stratigraphic position of the shale, with the best sealing mudstones, particularly those with high organic content, developed in the upper parts of transgressive systems tracts. High- stand systems tract shales were among the poorest seal rocks, especially where higher silt contacts in- duced compactional shielding of pores during burial, yielding lower entry pressures and estimated smaller column heights (Table 1). Hentz and Hongliu (2003) also observed that third-order transgressive shales were among the most important hydrocarbon seals in the middle to lower Miocene of shallow waters in offshore Louisiana.
As mentioned in the previous section on source rocks, organic-rich mudstones occur in several Mesozoic transgressive intervals, including the Oxfordian (middle Smackover marl), Tithonian (Haynesville–Bossier shales), Cenomanian–Turonian (Eagle Ford), and other zones. Preservation of organics deposited in these transgressive anoxic events is favored under low-oxygen conditions. This in turn reduces disruption of laminated fabrics by burrowing organisms and thus increases seal capacity (Dawson and Almon, 2005).
Mudstones with enhanced organic content are important in the Cenozoic section, although global anoxic events were not as frequent. Some organic enrichment occurs around the Paleocene–Eocene thermal maximum, as noted in locally restricted basins, because of salinity stratification or paleo-bathymetrical enclosures (Blanke et al., 2009; Cunningham et al., in press).
Mesozoic top seals include carbonate mudstones such as in the case of the Jurassic Norphlet deepwater play. Because the basal Smackover Formation is situated stratigraphically between the middle Smackover marl source and Norphlet sandstones, downward charging migration routes are required and demonstrated for this area (Godo, 2017). Other documented Mesozoic seals occur in the Tuscaloosa Formation, where middle marine shale units above the thick basal sandstone reservoir provide sufficient sealing capacity to hold hydrocarbons or act as barriers preventing vertical migration from CO2 storage sites (Lu et al., 2011). The MICP measurements of the middle Tuscaloosa mudstone at the Cranfield site indicate that large columns of CO2 could be retained below the shale during injection, a testament to the good seal integrity.
One caveat about using MICP data as a measure of seal rock capacity is the necessary requirement that a sufficiently large database of MICP be obtained to fully characterize the seals because a small sample set may miss the weakest mudrock that allows ver- tical leakage. Dawson and Almon (2005) based their classifications upon a large database, although the specific samples or size of the data set were not reported. A second approach, described below, uses the measured downhole fluid pressures to assess the seal capacity, independent of experimental analyses upon the bounding shale beds.
Column heights in subsurface traps have been directly related to the seal capacity of shales through testing and development of empirical relationships such as done by Sneider et al. (1997). However, column height can be controlled by a variety of other independent factors, including ineffective source rocks, fault juxtaposition leakage, overly long charge residence time, or unmapped spillpoints (Aplin and Larter, 2005). The important role of overpressured seal rocks (relative to underlying reservoirs) is also noted in some cases. The timing of overpressuring, however, controls its effect on both reservoirs and seals, and that factor tends to be block or prospect specific.
Subsurface Fluid Pressures as Indicators of Seal Rock Quality
The GOM mudstones with significant lateral or ver- tical seal capacity are commonly recognized as offsets in downhole pressure measurements (Downey, 1984). The magnitude of offsets may appear to be relatively small when pressure information from downhole measurements is simply plotted versus depth. Smaller offsets can be discerned using the excess pressure technique of Brown (2003). With this technique (described below), subtle yet important pressure changes can be illuminated, especially when re- cent vintage MDT or RCI data are available. Such an approach is most appropriate when recent vintage MDT or RCI data have accuracy and precision in the 0.01–0.002-psi (0.07–0.01-kPa) range versus older strain gauge data with accuracy of 1.01% (Chen, 2014).
Publicly available downhole pressure data, mainly from modular downhole tools such as the MDT and RCI for deep-water wells, can be obtained from the Bureau of Ocean Energy Management or Bureau of Safety and Environmental Enforcement to illuminate the quality of important seal rocks in Mesozoic and Cenozoic fields and discoveries. All data are first evaluated to eliminate low-quality pressure measurements caused by tool failure or low-permeability rock for which test time length is not sufficiently long enough to achieve equilibrium.
Excess pressure is calculated for reservoirs by selecting nominal fluid gradients that are based on compositional data (if available) or modified iteratively until a vertical line in the same fluid phase is achieved (assuming limited gravity segregation). The methodology is described in detail by Brown (2003).
We consider the seal rocks from two of the most important reservoirs in the basin, the Paleogene Wilcox and Jurassic Norphlet. These represent the largest and newest deep-water resources by UTRR, respectively.
Summary of Seal Rock Evaluation, Northern Gulf of Mexico
The examples of Cenozoic and Mesozoic seal rocks cited above are broadly representative of the northern GOM. Without effective seal rocks, the large closures in both the suprasalt and subsalt realm of the deep-water GOM would not have retained the immense volume of discovered hydrocarbons. In many cases, the same age seal rocks also extend to onshore areas as well (Condon et al., 2006; Dyman and Condon, 2006; Pitman et al., 2007). Coastal plain and delta plain or floodplain mudstones also are important seal rocks in onshore regions (Hackley, 2012b; Swanson et al., 2013b; Merrill, 2016), although traps are sometimes smaller given more limited mudstone continuity in nonmarine paleo-environments (Snedden, 2013, 2014). However, it is clear that seal rock capacity, here as offshore, is not simply a function of shale thickness because top seal lithology can vary from silty mudstones to claystones to carbonate-rich shales.
Seal rock failure caused by mechanical breakage of top seals does occur in the northern GOM Basin. These cases are found mainly in offshore areas where elevated crestal pore pressures in reservoirs and seal rocks on the steep flanks of relatively young (Cenozoic) salt-related structures converge on the least principal stress, causing leakage to the surface. However, examples from the supersalt minibasin fields like Mars, Auger, Genesis, and Popeye show that even in these cases, commercial volumes of hy- drocarbons can be retained (Seldon and Flemings, 2005).
TRAPS
As discussed in preceding sections, the northern GOM Super Basin has exceptional reservoirs, source rocks, seals, and other supporting elements such as favorable charge histories and salt canopy cooling processes that maintain the Mesozoic source rock viability at depth and out to abyssal plain waters. But without the presence of a diverse set of trap types, it is unlikely that the basin petroleum endowment would have passed the super basin threshold of 5 BOE. Salt tectonics and salt-generated or associated traps make a large part of the trap types. In addition, the long history of exploration would not be possible without such a broad and deep portfolio of trap styles that technology (seismic imaging, drilling, production) has progres- sively unveiled or made economically feasible.
Analysis of offshore and especially deep-water plays has stressed the important relationship of reservoirs and traps to the extensive salt canopy and compressional fold belts (Figure 17; Weimer et al., 1998, 2016b, 2017a, c; Duncan et al., 2018). Deep- water fields of the northern GOM are located in one of four provinces. (1) Basin province fields lie within salt or weld-bounded basins formed on the salt canopy. (2) Subsalt province fields lie below the salt canopy or its weld. The subsalt position creates technological challenges both to seismic im- aging and drilling. (3) Fold-belt province fields lie along the Mississippi Fan, Keathley–Walker, and Perdido fold belts. (4) Abyssal plain fields lie be- neath relatively flat basin floor basinward of the salt and fold belts Weimer et al. (2016b).
Recent drilling into abyssal plain, fold-belt, and subsalt provinces introduced an array of trap config- urations rarely penetrated in prior exploration phases (Figure 18). Salt canopies commonly are a major factor, providing both seals and structural discontinu- ities. Seismic imaging improvements allowed defini- tion of salt-cored folds at the autochthonous salt level (e.g., St. Malo; Figure 18A), autochthonous salt- inverted basins (turtle structures; Figure 18C), and allochthonous salt-cutoff traps and attics (Figure 18E, F). Even subtle traps such as the low-relief closure at the Tiber discovery (Figure 18D) and fault-dependent traps at Hadrian (Figure 18B) are now routinely identified on three-dimensional (3-D) seismic data. More unusual trap styles continue to be delineated and considered for drilling, such as encapsulated minibasins (Figure 18G) and Mesozoic expulsion rollovers such as in the protraction block (e.g., Harding et al., 2016).
Welds may also create traps by juxtaposing dif- ferent stratigraphic sections and seal where residual or shale gouge is present. Large bucket weld traps (Figure 18H) are common in the central GOM (Figure 17; Pilcher et al., 2011). Megaflaps, steeply dipping stratal packages along sides of diapirs or welds, and other high-relief structures develop from complex salt migration processes (Rowan et al., 2016). Several of these three-way truncation traps hold large columns of oil and gas (e.g., Mount et al., 2019; Wilkins et al., 2019).
Seismic Imaging of the Atlantis Trap: A Success Story
The discoveries and fields mentioned above (e.g., Mars, St. Malo, Appomattox, Cascade) are just a few of the success stories that northern GOM exploration has accumulated since offshore exploration as a whole began in the 1960s and major subsalt deep-water dril- ling initiated in the early 2000s (Zarra, 2007). Documenting the vast number of successful ventures is beyond the broad scope of this paper. But it is worthwhile considering the impact of advances in seismic imaging and illumination that were a direct result of seismic companies meeting an industry challenge to explore deep below the allochthonous salt canopy.
A case in point is the Atlantis field in the GC protraction block (GC 743; Figure 19, location 19 in Figure 9 and Appendix). Atlantis field is located at the boundary of the fold-belt and abyssal plain provinces (Figure 17). The trap is a relatively simple, deep salt- cored compressional anticline below the allochthonous salt canopy (Mander et al., 2012). Reservoirs are laterally continuous middle Miocene submarine fan deposits with high porosity (26%–32%) and permeability (500–1500 md). The reservoirs exhibit very high net-to-gross ratio and have little clay or cement (Mander et al., 2012).
However, the high quartz content and complex multiphase tectonic history have resulted in localized development of deformation bands and subseismic faults that have induced considerable reservoir com- partmentalization (Mander et al., 2012). Deformation bands are known as potential compartment-bounding features in several GOM fields where high net-to-gross sandstone reservoirs are present, including Appomattox (Godo, 2019) and Heidelberg (Mount et al., 2019; Wilkins et al., 2019).
Atlantis field is located partially below the allochthonous salt canopy; thus, imaging at deep levels is complicated by the variable salt thickness and sig- nificant water depth gradient at the Sigsbee escarpment (Mander et al., 2012). Exploration and development phase 1 3-D seismic data (Figure 20A) were replaced by an isotropic velocity rebuild and reimaging in 2008 (Figure 20B). This improved visualization of the structure and reservoir horizons. Subsequent wide-azimuth, tilted transverse isotropy, and reverse time-migration imaging were completed in 2010 (Figure 20C), which helped reduce reservoir uncertainty for the phase 2 development (Mander et al., 2012). A similar approach, with similar results, was used at the Mad Dog field area (Smith, 2013). Today, wide-azimuth and full-azimuth data are the dominant seismic acquisition technique in the northern and southern GOM Basin. New approaches such as on-bottom node data collection and full-waveform inversion are becoming more commonplace (Fiduk and Lyons, 2019). These and other acquisition, processing, and reimaging improvements have greatly reduced uncertainty in both exploration, development, and production phases (Leyendecker, 2014; Snedden and Galloway, 2019).
Finally, proximity of the northern GOM Basin to Houston, well known as the global center for offshore facilities design, drilling, and petroleum geo- science technology, should be noted. The numerous commercial research laboratories here have hosted development of a wide range of technologies from 3-D and four-dimensional seismic data, sequence stratigra- phy, subsea completions, tension-leg platforms, frac-pack completions, and many other innovative approaches to exploration, development, and production.
SUMMARY: INSIGHTS FROM THE NORTHERN GULF OF MEXICO SUPER BASIN FOR OTHER BASINS
It is useful to consider the broad insights that might be garnered from a super basin like the northern GOM. Some lessons are unique to the northern GOM Basin and some are relevant basin-wide, whereas other insights may have global applicability. These pertain to reservoirs, source rocks, seal rocks, charge history, and trap development, which are all the elements that make up an efficient, formidable world-class petroleum system.
To generate sufficient gross sandstone rock volume and a regional stacking of porous zones that constitute the hallmark of a super basin, a well-defined pathway from source terranes to depositional sink must be evident or at least inferred from tectonic reconstructions. In the case of the northern GOM Basin, prominent mountain belts were formed, exposed, and eroded over multiple structural events and paleoclimatic phases since the basin formed (Galloway et al., 2011; Snedden et al., 2018). The Cordilleran and Laramide orogens were the largest volumetric contributors for the Cenozoic, but the extant Appalachian tectonic highlands in the Me- sozoic and associated rejuvenated plateaus in the Miocene were also significant catchments during the Miocene (Boettcher and Milliken, 1994). These high rates of Cenozoic deposition on a mobile salt substrate also were a key factor in generating a diverse portfolio of salt tectonic structures and trap types. Relatively late Cenozoic burial, in comparison to other global basins, also improved charge–trap timing relationships.
Carbonate reservoirs, which are so important in the Mesozoic section of the onshore northern GOM and southern GOM, mainly require stable platforms; warm, equitable climates; and low-turbidity water to develop grainstone banks, thrombolytic buildups, plat- form margin reefs, and associated grainstone aprons. In addition, favorable postdepositional and burial diagenetic processes allow development of economic levels of porosity and permeability. Evidence from extensive drilling shows that all these depositional processes worked in the northern GOM.
Seal rocks also were formed during many of these depositional events and stratigraphic sequences. Given the large hydrocarbon endowment, seal rock quality is obviously sufficient in many intervals to resist both capillary and mechanical leakage over long geologic durations. Seal rocks are both stratigraphically and geographically widespread, a distribution reflecting allogenic processes (e.g., relative sea-level changes resulting in development of regional or global transgressions) and autogenic processes (e.g., submarine channel avulsion, fan abandonment, etc.).
Source rock occurrence, which includes organic production, preservation, maturation, migration, and appropriate timing relative to trap development, is optimized in the basin for a variety of reasons. Global OAEs were a facilitating factor, but basin-specific processes related to structural and paleogeographic restriction, salinity stratification, and reduced oxygen levels enhanced source rock quality so that at least two world-class source horizons (Cenomanian–Turonian and Tithonian centered) are present, with significant additions from the Jurassic Oxfordian, Paleogene, and other intervals. Multiple working source rocks ensure that failure cases of underfilled or wet traps caused by source inefficiency are relatively rare here.
The role of salt, particularly the allochthonous salt canopy, in enlarging the basin hydrocarbon endowment
cannot be overestimated. The emergence of the prolific subsalt play in the deep-water northern GOM reflects reduced heat flow, delayed maturation, and relatively recent migration from deeply buried Mesozoic source rocks into traps formed by salt tectonics.
Salt tectonics occurred over a long time frame, from early basin formation to near present day. This provides a wide diversity of trap types, but also an extended exploration history as plays matured from the hunt for simple diapiric traps, to the search for deep salt-cored compressional folds, bucket welds, and other complex tectonic configurations.
Paralleling and clearly driving this expanding portfolio of salt tectonic traps in the northern GOM is the increased sophistication of seismic acquisition, processing, and interpretation. Other basins with prominent salt bodies (e.g., Brazil, Caspian Basin, etc.) have undoubtedly benefited from major technical advances initiated to support industry activity in the GOM. This also applies to improvements in deep, high-pressure, high-temperature drilling, logging, and production in ultra–deep-water regimes.
The northern GOM Super Basin should be considered as a natural laboratory for illustrating the remarkable individual elements of a petroleum system but also the favorable confluence of these elements to yield one of the largest hydrocarbon endowments in the world. The macroeconomics of the basin, as they relate to market access, lease, and royalty terms, and so forth, obviously are a factor in its success. But these would not be relevant unless the underlying oil and gas commodity prize is available and in sufficient quantity to ensure that exploration, development, and production efforts can weather the ups and downs of past, current, and future supply–demand cycles.
September 2021 EIA Short-term Energy Outlook STEO Forecast, Release Date: Sept. 8, 2021 | Forecast Completed: Sept. 2, 2021 | Next Release Date: Oct. 13, 2021
FULL REPORT
https://www.eia.gov/outlooks/steo/pdf/steo_full.pdf
ALL FIGURES AND DATA
https://www.eia.gov/outlooks/steo/data.php?type=figures
FORECAST HIGHLIGHTS:
Global liquid fuels
The September Short-Term Energy Outlook (STEO) remains subject to heightened levels of uncertainty related to the ongoing recovery from the COVID-19 pandemic. U.S. economic activity continues to rise after reaching multiyear lows in the second quarter of 2020 (2Q20). U.S. gross domestic product (GDP) declined by 3.4% in 2020 from 2019 levels. This STEO assumes U.S. GDP will grow by 6.0% in 2021 and by 4.4% in 2022. The U.S. macroeconomic assumptions in this outlook are based on forecasts by IHS Markit. Our forecast assumes continuing economic growth and increasing mobility. Any developments that would cause deviations from these assumptions would likely cause energy consumption and prices to deviate from our forecast.
Brent crude oil spot prices averaged $71 per barrel (b) in August, down $4/b from July but up $26/b from August 2020. Brent prices have risen over the past year as result of steady draws on global oil inventories, which averaged 1.8 million barrels per day (b/d) during the first half of 2021 (1H21). We expect Brent prices will remain near current levels for the remainder of 2021, averaging $71/b during the fourth quarter of 2021 (4Q21). In 2022, we expect that growth in production from OPEC+, U.S. tight oil, and other non-OPEC countries will outpace slowing growth in global oil consumption and contribute to Brent prices declining to an annual average of $66/b.
More than 90% of crude oil production in the Federal Offshore Gulf of Mexico (GOM) was offline in late August following Hurricane Ida. NOTE: As of 9/8/2021, BSEE reports both oil and gas production to now be offline by only 77%. As a result of the outage, GOM production averaged 1.5 million b/d in August, down 0.3 million b/d from July. We expect that crude oil production in the GOM will gradually come back online during September and average 1.2 million b/d for the month before returning to an average of 1.7 million b/d in 4Q21.
Total U.S. crude oil production averaged 11.3 million b/d in June—the most recent monthly historical data point. We forecast it will remain near that level through the end of 2021 before increasing to an average of 11.7 million b/d in 2022, driven by growth in onshore tight oil production. We expect growth will result from operators beginning to increase rig additions, offsetting production decline rates.
We estimate that 98.4 million b/d of petroleum and liquid fuels was consumed globally in August, an increase of 5.7 million b/d from August 2020 but still 4.0 million b/d less than in August 2019. We forecast that global consumption of petroleum and liquid fuels will average 97.4 million b/d for all of 2021, which is a 5.0 million b/d increase from 2020, and by an additional 3.6 million b/d in 2022 to average 101.0 million b/d, almost even with 2019 levels.
U.S. regular gasoline retail prices averaged $3.16 per gallon (gal) in August, the highest monthly average price since October 2014. Recent gasoline price increases reflect rising wholesale gasoline margins amid relatively low gasoline inventories. In addition, recent impacts from Hurricane Ida on several U.S. Gulf Coast refineries are adding upward price pressures in the near term. Estimated gasoline margins surpassed 70 cents/gal in late August. We expect margins will remain elevated in the coming weeks as refining operations as U.S. Gulf Coast remain disrupted. We forecast that retail gasoline prices will average $3.14/gal in September before falling to $2.91/gal, on average, in 4Q21. The expected drop in retail gasoline prices reflects our forecast that gasoline margins will decline from currently elevated levels, both as a result of rising refinery runs as operations return in the first half of September following Hurricane Ida and because of typical seasonality.
Propane net exports in our forecast average close to 1.2 million b/d for the remainder of 2021, reflecting elevated global demand for U.S. propane and reduced supply from other sources related to ongoing OPEC+ production cuts. In 1H22, we assume global production of propane and butanes will rise as OPEC+ countries increase crude oil production. We expect this increase will limit additional demand for U.S. propane exports, despite growing global propane demand, and keep U.S. net propane exports close to 1.2 million b/d in 2022.
Natural Gas
In August, the natural gas spot price at Henry Hub averaged $4.07 per million British thermal units (MMBtu), which is up from the July average of $3.84/MMBtu. The August increase reflects hotter temperatures in August on average across the United States compared with July, which caused demand for natural gas in the electric power sector to be higher than expected. Prices rose further in late August when Hurricane Ida caused a decline in natural gas production in the GOM.
Henry Hub spot prices in August were $1.77/MMBtu higher than in August 2020. Steadily rising natural gas prices over the past year primarily reflects: growth in liquefied natural gas (LNG) exports, rising domestic natural gas consumption for sectors other than electric power, and relatively flat natural gas production. We expect the Henry Hub spot price will average $4.00/MMBtu in 4Q21, as the factors that drove prices higher during August lessen. Forecast Henry Hub prices this winter reach a monthly average peak of $4.25/MMBtu in January and generally decline through 2022, averaging $3.47/MMBtu for the year amid rising U.S. natural gas production and slowing growth in LNG exports.
More than 90% of natural gas production in the GOM was offline in late August following Hurricane Ida. GOM production of marketed natural gas averaged 1.9 billion cubic feet per day (Bcf/d) in August, down 0.4 Bcf/d from July. We expect that natural gas production in the GOM will gradually come back online during the first half of September and average 1.5 Bcf/d for the month before returning to an average of 2.1 Bcf/d in 4Q21.
We expect dry natural gas production will average 92.7 Bcf/d in the United States during 2H21—up from 91.7 Bcf/d in 1H21—and then rise to 95.4 Bcf/d in 2022, driven by natural gas and crude oil prices, which we expect to remain at levels that will support enough drilling to sustain production growth.
We expect that U.S. consumption of natural gas will average 82.5 (Bcf/d) in 2021, down 0.9% from 2020. U.S. natural gas consumption declines in 2021, in part, because electric power generators switch to coal from natural gas as a result of higher natural gas prices. In 2021, we expect residential and commercial natural gas consumption combined will rise by 1.2 Bcf/d from 2020 and industrial consumption will rise by 0.6 Bcf/d from 2020. Rising natural gas consumption in sectors other than the electric power sector results from expanding economic activity and colder winter temperatures in 2021 compared with 2020. We expect U.S. natural gas consumption will average 82.6 Bcf/d in 2022, mostly unchanged from 2021.
We estimate that U.S. natural gas inventories ended August 2021 at about 2.9 trillion cubic feet (Tcf), which is 7% lower than the five-year (2016–20) average for this time of year. Injections into storage this summer have been below the previous five-year average, largely as a result of hot weather and high exports occurring amid relatively flat natural gas production. We forecast that inventories will end the 2021 injection season (end of October) at almost 3.6 Tcf, which would be 5% below the five-year average.
Electricity, coal, renewables, and emissions
We expect the share of electricity generation produced by natural gas in the United States will average 35% in 2021 and 34% in 2022, down from 39% in 2020. In 2021, the forecast share for natural gas as a generation fuel declines in response to our expectation of a higher delivered natural gas price for electricity generators, which we forecast will average $4.69/MMBtu in 2021 compared with $2.39/MMBtu in 2020. The share of natural gas as a generation fuel also declines through 2022 because of expected increases in generation from renewable sources. As a result of the higher expected natural gas prices, the forecast share of electricity generation from coal rises from 20% in 2020 to about 24% in both 2021 and 2022. New additions of solar and wind generating capacity are offset somewhat by reduced generation from hydropower this year, resulting in the forecast share of all renewables in U.S. electricity generation to average 20% in 2021, about the same as last year, before rising to 22% in 2022. The nuclear share of U.S. electricity generation declines from 21% in 2020 to 20% in 2021 and to 19% in 2022 as a result of retiring capacity at some nuclear power plants.
We forecast that planned additions to U.S. wind and solar generating capacity in 2021 and 2022 will increase electricity generation from those sources. We estimate that the U.S. electric power sector added 14.7 gigawatts (GW) of new wind capacity in 2020. We expect 17.6 GW of new wind capacity will come online in 2021 and 6.3 GW in 2022. Utility-scale solar capacity rose by an estimated 10.5 GW in 2020. Our forecast for added utility-scale solar capacity is 15.9 GW for 2021 and 16.3 GW for 2022. We expect significant solar capacity additions in Texas during the forecast period. In addition, we project that after increasing by 4.5 GW in 2020, small-scale solar capacity (systems less than 1 megawatt) will grow 5.8 GW and 5.7 GW in 2021 and 2022 respectively.
Coal production in our forecast totals 601 million short tons (MMst) in 2021, 66 MMst more than in 2020. We expect demand for coal from the electric power sector to increase by 100 MMst in 2021 as a result of high natural gas prices, and coal exports to increase by 21 MMSt. However, production is unlikely to match those increases in demand in the near term due to capacity constraints at coal mines and limited available transportation. In 2022, we expect coal production to increase by 47 MMst to 648 MMst, despite our forecast of declines in coal consumption, as the production and transportation constraints experienced in 2021 ease. Secondary inventories of coal at electric utilities decreased in 1H21, and we forecast this trend will continue into 2H21 and 2022.
We estimate that U.S. energy-related carbon dioxide (CO2) emissions decreased by 11% in 2020 as a result of less energy consumption related to reduced economic activity and responses to COVID-19. For 2021, we forecast energy-related CO2 emissions will increase about 8% from the 2020 level as economic activity increases and leads to rising energy use. We also expect energy-related CO2 emissions to rise in 2022 but at a slower rate of 2%. We forecast that after declining by 19% in 2020, coal-related CO2 emissions will rise by 22% in 2021 and then decrease by 2% in 2022. Short-term changes in energy-related CO2 can be affected by temperature. A recent STEO supplement examines these dynamics.
Researchers trace geologic origins of Gulf of Mexico 'super basin' success, Date: January 15, 2021, Source: University of Texas at Austin
SUMMARY:
The GOM holds huge untapped offshore oil deposits that could help power the U.S. for decades. According to researchers, the basin's vast oil and gas reserves are the result of a remarkable geologic past. Only a fraction of the oil has been extracted and much remains buried beneath “ancient salt layers”, just recently illuminated by modern seismic imaging.
Note: Not to be concerned readers if we get stumped our GSPE resident “sub-salt” experts can assist.
The Gulf of Mexico holds huge untapped offshore oil deposits that could help power the U.S. for decades.
The energy super basin's longevity, whose giant offshore fields have reliably supplied consumers with oil and gas since the 1960s, is the result of a remarkable geologic past -- a story that began 200 million years ago among the fragments of Pangea, when a narrow, shallow seaway grew into an ocean basin, while around it mountains rose then eroded away.
The processes that shaped the basin also deposited and preserved vast reserves of oil and gas, of which only a fraction has been extracted. Much of the remaining oil lies buried beneath ancient salt layers, just recently illuminated by modern seismic imaging. That's the assessment of researchers at The University of Texas at Austin, who reviewed decades of geological research and current production figures in an effort to understand the secret behind the basin's success.
Because of its geological history, the Gulf of Mexico remains one of the richest petroleum basins in the world. Despite 60 years of continuous exploration and development, the basin's ability to continue delivering new hydrocarbon reserves means it will remain a significant energy and economic resource for Texas and the nation for years to come, said lead author John Snedden, a senior research scientist at the University of Texas Institute for Geophysics (UTIG).
"When we looked at the geologic elements that power a super basin -- its reservoirs, source rocks, seals and traps -- it turns out that in the Gulf of Mexico, many of those are pretty unique," he said.
The research was featured in a December 2020 special volume of the American Association of Petroleum Geologists Bulletin focused on the world's super basins: a small number of prolific basins that supply the bulk of the world's oil and gas.
According to the paper, the geologic elements that have made the Gulf of Mexico such a formidable petroleum resource include a steady supply of fine- and coarse-grained sediments, and salt: thick layers of it buried in the Earth, marking a time long ago when much of the ancient sea in the basin evaporated.
Geologically, salt is important because it can radically alter how petroleum basins evolve. Compared to other sedimentary rocks, it migrates easily through the Earth, creating space for oil and gas to collect. It helps moderate heat and keeps hydrocarbon sources viable longer and deeper. And it is a tightly packed mineral that seals oil and gas in large columns, setting up giant fields.
"The Gulf of Mexico has a thick salt canopy that blankets large portions of the basin and prevented us for many years from actually seeing what lies beneath," Snedden said. "What has kept things progressing is industry's improved ability to see below the salt."
According to the paper, the bulk of the northern offshore basin's potential remains in giant, deepwater oil fields beneath the salt blanket. Although reaching them is expensive and enormously challenging, Snedden believes they represent the best future for fossil fuel energy. That's because the offshore -- where many of the giant fields are located -- offers industry a way of supplying the world's energy with fewer wells, which means less energy expended per barrel of oil produced.
Snedden said there is still much to learn about hydrocarbons beneath the Gulf of Mexico, how they got there and how they can be safely accessed. This is especially true in the southern Gulf of Mexico, which was closed to international exploration until 2014. One of the few publicly available datasets was a series of UTIG seismic surveys conducted in the 1970s. Now, a wealth of prospects is emerging from new seismic imaging of the southern basin's deepwater region.
"When you look at recent U.S. oil and gas lease sales, Mexico's five-year plan, and the relatively small carbon footprint of the offshore oil and gas industry, I think it's clear that offshore drilling has an important future in the Gulf of Mexico," Snedden said.
Snedden's research was conducted within UTIG for the Gulf Basin Depositional Synthesis project (which he directs). The project has been continuously funded by an industry consortium since 1995. UTIG is a unit of the Jackson School of Geosciences.
https://www.sciencedaily.com/releases/2021/01/210115115240.htm
BSEE Monitors Gulf of Mexico Oil and Gas Activities in Response to Hurricane Ida, Release date 9/8/2021
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-monitors-gulf-of-mexico-oil-and-59
NEW ORLEANS — Bureau of Safety and Environmental Enforcement (BSEE) activated its Hurricane Response Team as Hurricane Ida made its way through the Gulf. The Hurricane Response Team continues to monitor offshore oil and gas operators in the Gulf as they return to platforms and rigs after the storm. The team works with offshore operators and other state and federal agencies until operations return to normal.
Based on data from offshore operator reports submitted as of 11:30 CDT today, personnel are still evacuated from a total of 73 production platforms, 13.04 percent of the 560 manned platforms in the Gulf of Mexico. Production platforms are the structures located offshore from which oil and gas are produced. Unlike drilling rigs, which typically move from location to location, production facilities remain in the same location throughout a project’s duration.
Personnel are still evacuated from 4 rigs (non-dynamically positioned), equivalent to 36.36 percent of the 11 rigs of this type currently operating in the Gulf. Rigs can include several types of offshore drilling facilities including jackup rigs, platform rigs, all submersibles and moored semisubmersibles.
A total of 2 dynamically positioned rigs remain off location. This number represents 13.33 percent of the 15 DP rigs currently operating in the Gulf. Dynamically positioned rigs maintain their location while conducting well operations by using thrusters and propellers. These rigs are not moored to the seafloor; therefore, they can move off location in a relatively short time frame. Personnel remain on-board and return to the location once the storm has passed.
As part of the evacuation process, personnel activate the applicable shut-in procedure, which can frequently be accomplished from a remote location. This involves closing the sub-surface safety valves located below the surface of the ocean floor to prevent the release of oil or gas, effectively shutting in production from wells in the Gulf and protecting the marine and coastal environments. Shutting in oil and gas production is a standard procedure conducted by industry for safety and environmental reasons.
From operator reports, it is estimated that approximately 76.88 percent of the current oil production in the Gulf of Mexico is shut in. BSEE estimates that approximately 77.25 percent of the gas production in the Gulf of Mexico is shut in. The production percentages are calculated using information submitted by offshore operators in daily reports. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day. The shut-in production figures therefore are estimates, which BSEE compares to historical production reports to ensure the estimates follow a logical pattern.
Facilities are currently being inspected. Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back online.
September 2021 (MER) Monthly Economic Review
Source: Jack Kleinhenz, Ph.D., CBE Chief Economist National Retail Federation
See pdf link below to view graphs:
https://cdn.nrf.com/sites/default/files/2021-08/2021%20Sep%20MER.pdf
https://nrf.com/research/monthly-economic-review-september-2021
Labor Market to Play Increasingly Critical Role in Economic Outlook
SYNOPSIS:
Consumer spending is currently far above pre-pandemic levels thanks to unprecedented monetary and fiscal policies that have backstopped demand by putting money into wallets for nearly a year and a half. Monthly child tax credit checks have recently begun adding to household income and will help spending. But as the economy moves forward into the later months of 2021, federal aid will taper off and there will be an important focus on the ability of the labor market to generate ongoing strength in wages and salaries to support spending. U.S. consumers remain in the mood to spend, but the labor market and job creation will play an increasing role in their ability to do so.
Labor market conditions influence confidence and spending, making them a critical driver of the broader economy and making the outlook for labor a critical indicator of economic conditions ahead. Fortunately, measures of the state of the labor market are abundant. New claims for unemployment insurance benefits are reported weekly, and the monthly Current Employment Survey jobs report, the monthly Job Openings and Labor Turnover Survey, and the quarterly Employment Cost Index all provide additional insights.
Every Thursday, the Labor Department reports the number of new claims filed for unemployment insurance, providing a view at both the state and national levels that can signal changes in consumer income and confidence along with the unemployment rate. For the week ending August 21, initial jobless claims totaled 353,000, holding near a pandemic low seen the week before. The four-week moving average was 366,500, a decrease of 11,500 from the previous week and the lowest level since 225,500 in mid-March 2020 just before the economy began to shut down because of the pandemic. The claims data provides an important snapshot on how many workers are choosing to return to the labor force and forgoing unemployment benefits. While the impact from the delta variant does not yet appear to be a drag on job gains, further declines in unemployment claims could slow in the coming weeks as the variant intensifies.
The unemployment claims numbers are consistent with other labor market data. Payroll gains were strong in July, rising by 943,000 jobs, the largest increase in 11 months, and averaged 832,000 jobs per month over three months.
JOLTS data shows that nonfarm job openings rose to 10.07 million in June, a new record high, and that there were 9.48 million unemployed Americans – just under one unemployed worker for every job opening in the economy. That speaks to the tightness of the labor market, with more job openings than people looking for work. In retail, there were 1.15 million job openings, but merchants were able to fill only 1.12 million of the positions.
Different states have drastically different populations and are home to different industries, so their job growth rates vary greatly, and state policies such as taxes and economic regulation can also play a role. Nonetheless, the July employment report for state and regional economies kicked off the third quarter on a strong footing even as labor shortages persisted and the delta variant spread more invasively in some regions than others. Payrolls increased in 38 states and the District of Columbia and were essentially unchanged in 12 states. Over the year, nonfarm employment increased in all 50 states and the District.
The quarterly Employment Cost Index is complex data but is the preferred measure of compensation, reflecting trends in costs to employers for total compensation, wages and benefits while controlling for composition of the workforce so as not to be skewed by employment shifts among occupations and industries. The index ticked up to 2.9 percent growth for the 12-month period ending in June, the highest rate since the fourth quarter of 2018. Growth had hovered between 2.7 percent and 2.9 percent for the 10 quarters prior to the pandemic and decreased to 2.4 percent in September 2020. Wages and salaries – a key component of the index – increased 3.2 percent for the 12 months ending in June.
Businesses across the economy are reporting that it is difficult to find the workers they need and have responded by raising pay, which raises concerns about inflationary pressures starting to build. Trends in wages and salaries are critical for the economic outlook as policymakers debate whether the recent spike in inflation will be temporary or longer lasting. The bulk of the recent upturn in U.S. inflation has been driven primarily by supply chain bottlenecks and low levels of inventories, but higher labor costs are often passed on to consumers and are considered a precursor of broader inflation. We will be monitoring labor market developments intently to determine if expanded payrolls expected in the coming months will influence inflationary pressure, especially as wages and salaries increase.
While second-quarter economic activity was softer than expected, consumer spending was quite strong. Looking forward, continued momentum in the job market will provide the income needed to support household spending. Meanwhile, the delta variant is on the rise and could impact spending for restaurants, travel and accommodations, delaying job recovery in those industries. Early reports on consumer sentiment have underscored that there are rising concerns. We are closely watching COVID-19 cases and hospitalizations, which represent a downside risk to the economic outlook. At this point, some disruption to retail sales is anticipated but at a relatively modest level, and we have not trimmed back our expectations for retail sales this year. Retailers continue to safely serve customers and even temporary store closures are unlikely. If anything, the retreat in services spending will provide some wallet shift back to discretionary goods spending.
BSEE Monitors Gulf of Mexico Oil and Gas Activities in Response to Hurricane Ida, UPDATE RELEASED TODAY, 9/2/2021
Note: Total GOM production shut-in rose from BSEE’s earlier 9/1/2021 report, total platforms and rigs evacuated declined. Under the circumstances, it would be expected to wax and wane initially.
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-monitors-gulf-of-mexico-oil-and-53
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-monitors-gulf-of-mexico-oil-and-52
https://www.bsee.gov/newsroom/latest-news/statements-and-releases/press-releases/bsee-monitors-gulf-of-mexico-oil-and-49
NEW ORLEANS — Bureau of Safety and Environmental Enforcement (BSEE) activated its Hurricane Response Team as Hurricane Ida made its way through the Gulf. The Hurricane Response Team is monitoring offshore oil and gas operators in the Gulf as they evacuate platforms and rigs in response to the storm. The team works with offshore operators and other state and federal agencies until operations return to normal and the storm is no longer a threat to Gulf of Mexico oil and gas activities.
Based on data from offshore operator reports submitted as of 11:30 CDT today, personnel have been evacuated from a total of 177 production platforms, 31.61 percent of the 560 manned platforms in the Gulf of Mexico. Production platforms are the structures located offshore from which oil and gas are produced. Unlike drilling rigs, which typically move from location to location, production facilities remain in the same location throughout a project’s duration.
Personnel have been evacuated from six rigs (non-dynamically positioned), equivalent to 54.55 percent of the 11 rigs of this type currently operating in the Gulf. Rigs can include several types of offshore drilling facilities including jackup rigs, platform rigs, all submersibles and moored semisubmersibles.
A total of 4 dynamically positioned rigs have moved off location out of the storm’s projected path as a precaution. This number represents 26.7 percent of the 15 DP rigs currently operating in the Gulf. Dynamically positioned rigs maintain their location while conducting well operations by using thrusters and propellers. These rigs are not moored to the seafloor; therefore, they can move off location in a relatively short time frame. Personnel remain on-board and return to the location once the storm has passed.
As part of the evacuation process, personnel activate the applicable shut-in procedure, which can frequently be accomplished from a remote location. This involves closing the sub-surface safety valves located below the surface of the ocean floor to prevent the release of oil or gas, effectively shutting in production from wells in the Gulf and protecting the marine and coastal environments. Shutting in oil and gas production is a standard procedure conducted by industry for safety and environmental reasons.
From operator reports, it is estimated that approximately 93.55 percent of the current oil production in the Gulf of Mexico has been shut in. BSEE estimates that approximately 91.29 percent of the gas production in the Gulf of Mexico has been shut in. The production percentages are calculated using information submitted by offshore operators in daily reports. Shut-in production information included in these reports is based on the amount of oil and gas the operator expected to produce that day. The shut-in production figures therefore are estimates, which BSEE compares to historical production reports to ensure the estimates follow a logical pattern.
After the storm has passed, facilities will be inspected. Once all standard checks have been completed, production from undamaged facilities will be brought back online immediately. Facilities sustaining damage may take longer to bring back online.
EDITED
Oil steadies; OPEC+ sticks to gradual output hikes, By Stephanie Kelly, reuters.com
https://www.reuters.com/business/energy/oil-steady-ahead-opec-supply-decision-2021-09-01/
Summary
* OPEC+ sticks to gradual oil output hikes, ups demand forecast
* U.S. crude stocks down, gasoline stocks up - EIA
* U.S. refineries aim to restart after Hurricane Ida
NEW YORK, Sept 1 (Reuters) - Oil prices steadied on Wednesday after OPEC and its allies agreed to stick to their existing policy of gradual oil output increases.
Brent crude fell 4 cents to settle at $71.59 a barrel. U.S. West Texas Intermediate (WTI) crude rose 9 cents to settle at $68.59 a barrel.
Brent had plumbed a session low of $70.42 a barrel, while WTI fell as low as $67.12 a barrel.
The Organization of the Petroleum Exporting Countries and allies led by Russia, a group known as OPEC+, agreed to stick to a policy from July of phasing out record output cuts by adding 400,000 barrels per day (bpd) a month to the market. [nL1N2Q30F8]
Still, the group revised up its 2022 demand outlook and faces U.S. pressure to raise production more quickly.
Wednesday's decision means that OPEC+ will release 400,000 bpd to the market in October again, after already doing so in September. The next OPEC+ meeting is scheduled for Oct. 4.
"While the effects of the COVID-19 pandemic continue to cast some uncertainty, Market fundamentals have strengthened and OECD stocks continue to fall as the recovery accelerates," OPEC+ said in a statement.
OPEC+ has fulfilled a goal of removing excess oil from the global market and it is important to keep the market balanced, said Russia's top negotiator, Alexander Novak.
U.S. gasoline stocks (USOILG=ECI) rose by 1.3 million barrels last week, the Energy Information Administration said. Analysts had expected a 1.6 million-barrel drop. Rising coronavirus infections could curtail demand in the United States in coming weeks, along with seasonal declines after summer driving season wanes.
"The gasoline build came as Tropical Storm Henry shut traffic on the East Coast which was a big hit to summer driving season," said Bob Yawger, director of energy futures at Mizuho in New York.
The jump in gasoline inventories came even as product supplied, a measure of demand, topped 22 million bpd for the first time ever, EIA said.
U.S. crude inventories (USOILC=ECI) fell by 7.2 million barrels last week to 425.4 million barrels. Analysts had expected a 3.1 million-barrel drop.
U.S. crude prices are expected to remain under pressure as offshore oil and gas production in the Gulf of Mexico gradually recovers. However, reviving Louisiana refineries shut by Hurricane Ida could take weeks, analysts said.
Summary of Weekly Petroleum Data for the week ending August 27, 2021
https://ir.eia.gov/wpsr/wpsrsummary.pdf
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 7.2 million barrels from the previous week. At 425.4 million barrels, U.S. crude oil inventories are about 6% below the five year average for this time of year. Total motor gasoline inventories increased by 1.3 million barrels last week and are about 2% below the five year average for this time of year. Finished gasoline and blending components inventories both increased last week. Distillate fuel inventories decreased by 1.7 million barrels last week and are about 9% below the five year average for this time of year. Propane/propylene inventories increased by 0.5 million barrels last week and are about 20% below the five year average for this time of year. Total commercial petroleum inventories decreased by 13.6 million barrels last week.
U.S. crude oil refinery inputs averaged 15.9 million barrels per day during the week ending August 27, 2021 which was 133,000 barrels per day less than the previous week’s average. Refineries operated at 91.3% of their operable capacity last week. Gasoline production decreased last week, averaging 9.9 million barrels per day. Distillate fuel production decreased last week, averaging 4.8 million barrels per day.
U.S. crude oil imports averaged 6.3 million barrels per day last week, up by 183,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.3 million barrels per day, 13.9% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 1.1 million barrels per day, and distillate fuel imports averaged 364,000 barrels per day.
Total products supplied over the last four-week period averaged 21.4 million barrels a day, up by 17.1% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.5 million barrels a day, up by 6.9% from the same period last year. Distillate fuel product supplied averaged 4.1 million barrels a day over the past four weeks, up by 10.4% from the same period last year. Jet fuel product supplied was up 51.7% compared with the same four- week period last year.
HIGHLIGHTS
https://www.eia.gov/petroleum/supply/weekly/pdf/highlights.pdf
U.S. crude oil refinery inputs averaged 15.9 million barrels per day during the week ending August 27, 2021 which was 133,000 barrels per day less than the previous week’s average. Refineries operated at 91.3% of their operable capacity last week. Gasoline production decreased last week, averaging 9.9 million barrels per day. Distillate fuel production decreased last week, averaging 4.8 million barrels per day.
U.S. crude oil imports averaged 6.3 million barrels per day last week, up by 183,000 barrels per day from the previous week. Over the past four weeks, crude oil imports averaged about 6.3 million barrels per day, 13.9% more than the same four-week period last year. Total motor gasoline imports (including both finished gasoline and gasoline blending components) last week averaged 1.1 million barrels per day, and distillate fuel imports averaged 364,000 barrels per day.
U.S. commercial crude oil inventories (excluding those in the Strategic Petroleum Reserve) decreased by 7.2 million barrels from the previous week. At 425.4 million barrels, U.S. crude oil inventories are about 6% below the five year average for this time of year. Total motor gasoline inventories increased by 1.3 million barrels last week and are about 2% below the five year average for this time of year. Finished gasoline and blending components inventories both increased last week. Distillate fuel inventories decreased by 1.7 million barrels last week and are about 9% below the five year average for this time of year. Propane/propylene inventories increased by 0.5 million barrels last week and are about 20% below the five year average for this time of year. Total commercial petroleum inventories decreased by 13.6 million barrels last week.
Total products supplied over the last four-week period averaged 21.4 million barrels a day, up by 17.1% from the same period last year. Over the past four weeks, motor gasoline product supplied averaged 9.5 million barrels a day, up by 6.9% from the same period last year. Distillate fuel product supplied averaged 4.1 million barrels a day over the past four weeks, up by 10.4% from the same period last year. Jet fuel product supplied was up 51.7% compared with the same four-week period last year.
The West Texas Intermediate crude oil price was $68.84 per barrel on August 27, 2021, $6.59 above last week’s price and $25.88 more than a year ago. The spot price for conventional gasoline in the New York Harbor was $2.285 per gallon, $0.277 more than last week’s price and $1.001 above a year ago. The spot price for ultra-low sulfur diesel fuel in the New York Harbor was $2.107 per gallon, $0.210 above last week’s price and $0.903 over a year ago.
The national average retail regular gasoline price was $3.139 per gallon on August 30, 2021, $0.006 per gallon less than last week’s price but $0.917 over a year ago. The national average retail diesel fuel price was $3.339 per gallon, $0.015 above last week’s price but $0.898 over a year ago.
WTI September contract over $70 a barrel today, September 2, 2021. Currently $69.99/bbl 16:21 CDT
https://oilprice.com/oil-price-charts/45
20th OPEC and non-OPEC Ministerial Meeting concludes:
https://www.opec.org/opec_web/en/press_room/6567.htm
The 20th OPEC and non-OPEC Ministerial Meeting (ONOMM), held via videoconference, concluded on Wednesday, 1 September 2021.
The Meeting noted that, while the effects of the COVID-19 pandemic continue to cast some uncertainty, market fundamentals have strengthened and OECD stocks continue to fall as the recovery accelerates.
The Meeting welcomed the positive performance of Participating Countries in the Declaration of Cooperation (DoC). Overall conformity to the production adjustments was 110% in July including Mexico (109% without Mexico), reinforcing the trend of high conformity by Participating Countries.
In view of current oil market fundamentals and the consensus on its outlook, the Meeting resolved to:
Reaffirm the decision of the 10th OPEC and non-OPEC Ministerial meeting on 12 April 2020 and further endorsed in subsequent meetings, including the 19th ONOMM on 18 July 2021.
Reconfirm the production adjustment plan and the monthly production adjustment mechanism approved at the 19th ONOMM and the decision to adjust upward the monthly overall production by 0.4 mb/d for the month of October 2021.
Extend the compensation period until the end of December 2021 as requested by some underperforming countries and request that underperforming countries submit their compensation plans by 17 September 2021. Compensation plans should be submitted in accordance with the statement of the 15th ONOMM.
Reiterate the critical importance of adhering to full conformity and to the compensation mechanism, taking advantage of the extension of the compensation period until the end of December 2021.
Hold the 21st OPEC and non-OPEC Ministerial Meeting on 4 October 2021.
Straight from the horse’s mouth.
BOEM Updates Gulf of Mexico Lease Sale 257 Record of Decision
https://www.boem.gov/boem-updates-gulf-mexico-lease-sale-257-record-decision
Release Date 8/31/2021
As follow up to the Department of the Interior’s announcement on August 24, BOEM has posted an updated Record of Decision (ROD) for Lease Sale 257 (LS 257) to its website as of 8/31/2021. See link below:
https://www.boem.gov/sites/default/files/documents/oil-gas-energy/GOM-LS-257.pdf
The Department has determined to move forward with the process for Gulf of Mexico (GOM) Lease Sale 257, consistent with the Secretary’s authorities and discretion under applicable law.
This ROD identifies BOEM’s selected alternative (i.e., Alternative A) for proposed LS 257, which is analyzed in the Gulf of Mexico OCS Lease Sale: Final Supplemental Environmental Impact Statement 2018 (2018 GOM Supplemental EIS). Alternative A allows for a proposed GOM regionwide lease sale encompassing all three planning areas: Western Planning Area (WPA); Central Planning Area (CPA); and a small portion of the Eastern Planning Area (EPA) not under congressional moratorium.
As stated in the Department of the Interior’s announcement, BOEM expects a Final Notice of Sale for LS 257 to publish in September, with a lease sale to follow in the fall of this year.
Good afternoon Trip,
You need to revisit your Tau budget and actual well costs. Your numbers are incorrect and that is not even considering the insurance monies received by Gulfslope and Delek.
How many GOM wells have been drilled? 10,000, 20,000, 30,000, 40,000, 50,000…. Let us be conservative and just go with 50K.
W & T Offshore’s GOM Mahogany field is reporting a 100% success rate, and Mr. Seitz has stated the Mahogany field is analogous to the Tau field.
The one thing you are correct about today is I am LOL.
Mrs. Smith
Oil posts biggest weekly gains in over a year ahead of Hurricane Ida
https://www.reuters.com/business/energy/oil-climbs-storm-approaches-gulf-mexico-production-hub-2021-08-27/
Summary
*Benchmarks rise over 10% in biggest weekly gains since June 2020
*Oil firms cut U.S. Gulf of Mexico output by 59% ahead of Ida
*U.S. dollar declines after U.S. Fed Chair Powell comments
*Fed's Powell said current high inflation will likely pass
*U.S. oil rigs rise for 12th straight month -Baker Hughes
NEW YORK, Aug 27 (Reuters) - Oil prices rose 2% on Friday, posting their biggest weekly gains in over a year, as energy firms began shutting U.S. production in the Gulf of Mexico ahead of a major hurricane expected to hit early next week.
Brent futures rose $1.63, or 2.3%, to settle at $72.70 a barrel, while U.S. West Texas Intermediate (WTI) crude rose $1.32, or 2.0%, to settle at $68.74.
That was the highest close for Brent since Aug. 2 and for WTI since Aug. 12.
For the week, Brent gained over 11% and WTI rose more than 10%, which was the biggest weekly percentage gains for both since June 2020.
Energy traders are pushing crude prices higher in anticipation of disruptions in output in the Gulf of Mexico and on growing expectations OPEC+ might resist raising output given the recent Delta variant impact over crude demand," Edward Moya, senior market analyst at OANDA, said.
Oil producers on Friday have shut-in 59% of Gulf of Mexico crude production as the ninth-named storm of the season barreled towards the key U.S. offshore oilfields, according to the Bureau of Safety and Environmental Enforcement (BSEE)
Oil and gas companies evacuated 89 platforms and one rig in preparation, shutting in production ahead of the storm's arrival They also moved 11 drill vessels out of harm's way by midday Friday, the offshore regulator said.
Energy producers also cut 1.09 million cubic feet of natural gas production, or 49% of their output, according to the BSEE.
Gulf of Mexico offshore wells account for 17% of the nation's oil production and 5% of its dry gas production, according to the U.S. Energy Information Administration, while over 45% of total U.S. refining capacity lies along the Gulf Coast.
U.S. crude prices settled 2% higher on Friday at $68.74 a barrel due to supply fears surrounding the storm.
“Historically speaking, crude oil rallies as hurricanes approach, despite the fact that refineries do not need crude oil when they are shut down during a storm," said Bob Yawger, director of energy futures at Mizuho in New York.
Offshore crude oil prices and Gulf Coast crude grades were strengthening due to the hurricane, traders said. Mars crude - considered the benchmark sour grade in the Gulf Coast - firmed to trade at about $1.45 below benchmark futures, rising by about $1 since Tuesday.
U.S. oil rigs rose five to 410 this week, their highest since April 2020, energy services firm Baker Hughes Co (BKR.N) said. In August, drillers added 25 oil rigs, the most in a month since January, putting the oil rig count up for 12 months in a row for the first time since July 2017.
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/ogj_rig_count.pdf
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/WeeklyRigCountUpdate.pdf
Oil prices were also supported by a decline in the U.S. dollar (.DXY) to a one-week low versus a basket of other currencies following comments by U.S. Federal Reserve Chair Jerome Powell.
A weaker U.S. dollar makes oil less expensive for holders of other currencies.
Powell, in a speech that affirmed an ongoing U.S. economic recovery and explained why there is no rush to tighten monetary policy, gave a detailed account on Friday of why he regards a spike in inflation as temporary and offered no signal on when the central bank plans to cut its asset purchases beyond saying it could be "this year."
Looking ahead, the Organization of the Petroleum Exporting Countries and its allies, including Russia, a group known as OPEC+, will meet on Sept. 1 to discuss its plan from July to raise output by 400,000 barrels per day every month for the next several months.
“Finding Delek was not easy”. You have made that statement before. How difficult “was it to find” a well known international multi-billion dollar company like Delek Group? Not only did Gulfslope Energy secure Delek Group as a 75% working interest partner, Delek became a 24% capital shareholder in Gulfslope.
“Is it the subsalt thing scaring partners” What are you saying, “subsalt” is now the GOM bogeyman? Even with the advancements in imaging and drilling rigs? Oh no, someone needs to warn every single GOM Oil and Gas E&P company drilling subsalt wells if that is the case.
Is oil and gas exploration in South Africa free of challenges and risks?
Mrs. Smith
8/20/2021 GOM Offshore Rig Count increased by 1 for an overall count of 14 rigs. The Total US Oil and Gas Rig Count reflects 503 rigs an increase of 3.
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/WeeklyRigCountUpdate.pdf
http://www.dnr.louisiana.gov/assets/TAD/data/drill_weekly/ogj_rig_count.pdf
8/9/2021 Weekly Global Offshore Rig Counts:
https://www.westwoodenergy.com/news/infographics/weekly-global-offshore-rig-counts
Mrs. Smith
You made some valid points on the attached post. I have a few to add.
“For the tax year ended September 30, 2020, the Company had approximately $65.6 million of net operating losses (“NOL”), approximately $32.1 million of which will expire from 2032 to 2038, and approximately $33.5 million of which can be carried forward indefinitely. All of the Company’s NOLs are allowable as a deduction against 100 percent of future taxable income since they were generated prior to the effective date of limitations imposed by the Tax Cut and Jobs Act (TCJA) of 2017 and Coronavirus Aid, Relief, and Economic Security Act (CARES) of 2020”
Under the Biden administration, US fossil fuel tax subsidies could decline and tax rates increase. How much monetary worth is in Gulfslope’s 66 milllion of Net Operating Losses? Could be in the range of 14mm to 23mm.
Gulfslope’s Balance Sheet is clear of almost all 3rd party debt. They reflect no long-term liabilities. Gulfslope’s working capital deficit of 12 million consist almost entirely of loans and interest payable to Mr. Seitz the CEO (8.7mm plus 3mm). “Gulfslope has historically operated it’s business with working capital deficits and those deficits have been funded by equity and debt investments and loans from management.”
A little history on Gulfslope’s Convertible Promissory Notes of $8.7 mm with Mr. Seitz. It all started back in 2013 with the notes being due on demand. Not once has Mr. Seitz demanded partial payment of the his notes from Gulfslope since it’s inception, even after Gulfslope received the $7.5 million under the Tau insurance claim. $5.3mm of the notes are convertible into shares of CS at a conversion price of $0.12 per share.
“Capitalized exploratory well costs remain pending the outcome of exploration activities involving the drilling of the Tau No. 2 well (twin well). The Company capitalizes exploratory well costs into oil and gas properties until a determination is made that the well has either found proved reserves or is impaired. If proved reserves are found, the capitalized exploratory well costs are reclassified to proved properties. The well costs are charged to expense if the exploratory well is determined to be impaired.”
Gulf slope continues to see economic and operational viability in the Tau’s unproved oil and gas properties. Otherwise, why would they continue to capitalize well costs and seek a rig contract. The Tau prospect’s economics are still strong in my opinion.
Mrs. Smith
EDITED
Does CENAQ’s BOD or principals individually hold a significant ownership stake in Gulfslope similar to Delek Group’s 24%? With the increase in Gulfslope’s outstanding shares and investor transfers probably closer to 2%. The SEC does not even require an individual to file a report unless they acquire more than 5% of a company’s shares.
Mrs. Smith