Industry Updates Summer 2021
|Jump to Section:||Center News||Research News||Education News||Diversity News||Industry News||Publications|
Energy Industry Business Environment
Bruce Cook, Purdue University, CISTAR Research and Industry Advisor
EIA’s 2021 Annual Energy Outlook was released in February 2021. Key takeaways from 2021 AEO were:
· Returning to 2019 levels of US energy consumption takes years; energy related carbon dioxide emissions fall further before leveling off or rising.
· Renewable energy incentives and falling technology costs support robust competition with natural gas as coal and nuclear power decrease in the electricity mix.
· Continuing record-high domestic energy production supports natural gas exports but does not necessarily mean growth in the US trade balance in petroleum products.
The impacts of Covid-19 pandemic and economic interventions on the current energy landscape are very evident, and future uncertainties remain on the extent and rate of recovery for both overall energy and hydrocarbon demand. Pandemic impacts to the hydrocarbon industry in the US were not symmetric across all sectors. 2020 US NGL production growth continued, showing little impact (see article below), while oil and natural gas demand saw significant declines. US oil demand and production declined due to a record drop in refinery crude runs as transportation fuel consumption steeply declined. Although transportation fuel consumption is increasing, EIA projects that refinery crude runs will not reach 2019 levels until 2025. Longer term, EIA, still projects that motor gasoline will be the predominant fuel for passenger vehicles in US out to 2050.
Largely driven by OPEC, OPEC+ and US Oil Shale production reductions, benchmark oil prices have rebounded into the $60/BBL range in 1Q2021. However, EIA forecasts soft crude prices into the second half of the year reflecting potential increased production and uncertainty in the rate that the US and world economies open back up from Covid-19 restrictions. Also, the world has historic high spare oil production capacity, which could limit any future oil price rise.
U.S. production of natural gas plant liquids (NGPL), which includes the recovery of ethane, propane, normal butane, isobutane, and natural gasoline from raw natural gas processed at gas processing plants, grew in 2020, even as crude oil and natural gas production declined. U.S. annual average NGPL production grew 7.0% in 2020, reaching 5.2 million barrels per day (b/d). U.S. field production of crude oil and natural gas both decreased over this period, by 7.7% and 1.9%, respectively.
Propane from natural gas processing plants increased by 89,000 b/d, or 5.6%. Production of butanes (combined isobutane and normal butane increased by 40,000 b/d, or 4.8%. Production of ethane, which serves as a petrochemical feedstock for ethylene crackers, showed the largest increase, growing by 182,000 b/d, or 9.9%. Natural gas processing plant operators have discretion in the quantities of ethane recovered from raw natural gas, so ethane production generally responds to demand. When ethane prices are low relative to dry natural gas prices, processing plant operators may choose to leave ethane in the natural gas and sell it into the natural gas market at its heat value. This process is known as ethane rejection. When ethane prices rise higher than natural gas prices on a heat-value equivalent basis, natural gas processing plant operators may choose to recover the ethane along with other NGPLs and sell it at their market value into the petrochemical sector.
Throughout 2020, ethane prices were, on average, 83¢ per million British thermal units (MMBtu), or 43%, higher than dry natural gas, spurring higher rates of recovery. EIA estimates that petrochemical industry capacity to consume ethane as a feedstock grew by 270,000 b/d as a result of new petrochemical cracking capacity that came online in late 2019 and throughout 2020. Although the petrochemical industry was also affected by the COVID-19-pandemic and multiple hurricanes which made landfall along the Gulf Coast, year-over-year domestic demand for ethane as a feedstock grew 165,000 b/d (10.7%).
EIA’s Annual Energy Outlook projects future ethane demand to continue growing. Ethane exports are also expected to increase as overseas petrochemical plants designed to consume ethane imported from the United States are completed. Rising demand and continuing growth in U.S. natural gas production are projected to increase U.S. ethane production by 750,000 b/d, reaching 2.76 million b/d by 2050. Production of other NGPLs is projected to peak in 2031 and remain relatively flat through the remainder of the projection as production of natural gas gradually shifts into areas where the share of NGPLs in the raw natural gas is lower.
Gary Sawyer, Purdue University, Industry Consultant
Our last newsletter discussed how operating and capital costs are used to set targets for key process performance variables. An example Tornado Diagram showed where to prioritize research efforts for soft oxidation chemistry with sulfur.
We are also interested in converting natural gas liquids (NGLs) to fungible motor fuels at locations near wells with stranded gas (Figure 1). These small scale units consist of dehydrogenation and oligomerization steps with simple recovery of liquid fuel products. Spreadsheet models tie together operating conditions and performance targets for each step into a process material balance, which is used for:
· Rough equipment sizing and associated capital costs
· Utility consumptions and costs
· Product and byproduct rates with sales value
· Payback period, calculated as capital cost divided by annual variable margin.
The simple spreadsheet models lack the detail and rigor of a fully simulated PFD, but allow for fast screening of variables such as:
· Reaction temperature and pressure
· Selectivity and conversion of key materials
· Feed flow and component concentrations
· Optional design considerations such as recycle streams and selective component separations using membranes.
For these screening evaluations, we select payback period, described above, as the target economic metric. Recognizing that only critical equipment is included in the capital cost, we choose an aggressive target of 1 year payback. The shorter the payback, the more attractive the economics. The figure below is a Tornado Diagram for a 10 MMSCFD plant patterned after Figure 2. Model assumptions are listed on the left with the values that produce a 1 year payback, which in this case derives from an estimated $8.5 MM capital with $8.5MM/yr variable margin (not shown). Location (NGL concentration) and olefin conversion in oligomerization are more impactful on the economics than, say, catalyst life. Prices are reflective of $3/MMBTU natural gas and $50/bbl crude oil.
Figure 1 (Left) Steps in Making CISTAR fuel. Figure 2 (Right) Tornado Diagram for CISTAR Flowsheet