RE:Grey Hydrogen Part 1excellent post, i enjoyed reading it. many energy options for the future.
retiredengexec wrote: Part 2 will take a bit longer as the midstream portion is a bit more complex.
Part 1 Grey Hydrogen – Upstream Metrics/Executive Summary
In this analysis, it is assumed that 1.1 million bbls pd of oil used for transportation fuel and 3.5 Bcfpd of Nat gas used for home heating and commercial space heating is converted to hydrogen. This would eliminate 240 MT of CO2 per year. The hydrogen would be manufactured in a huge complex located immediately outside of Edmonton owing primarily due to proximity to CCS reservoirs and availability of Natural gas on the TCPL system.
The above load results in the need to make 75,000 metric tonnes of H2 each day. Current worldwide production is about 80,000 T/day. Feed/outputs are as follows: 1.41 million barrels per day of water (only 1% of the North Saskatchewan River), 12.5 Bcfpd of natural gas (75% of all Cdn Natural gas production) and 1,500 MW of electricity. Outputs are 75,000 kg of H2 (29.8 Bcfpd) and 12.9 Bcfpd of CO2 which is 3.8 million bbls per day of CO2 at sequestered reservoir conditions.
The storage requirement (and risk) to achieve green status in this case is huge. Over a twenty-year timeline over 117 Tcf of CO2 would need to be disposed of, or 3.5 billion barrels. The proposed reservoir would be the Devonian, which is the reservoir that Leduc #1 was produced from. This well was part of an extensive reef trend that ran from west of Red Deer to North east of Edmonton. In total this trend produced 4.5 billion bbls of oil and 31 Tcf of gas. At the aforementioned rates these reservoirs will be filled in 10 years. To use this trend about 1,000 old wells would have to checked and potentially repaired. After the reefs are “filled up” injection would take place on very flat widespread platforms charged with water. Unfortunately, they have very poor injectivity. For this reason, a minimum of 190 wells will be required to avoid the risk that CO2 had to be flared. Why you ask don’t we use other existing reservoirs? Well, we need them for H2 storage as demand is seasonal and with H2 you need about triple current storge of 1 TCF per year.
Before talking about costs, consider that all of Alberta’s natural gas would be used for H2 production. BC production would be used to fuel industrial demand in the rest of Canada. All in-situ oil production would be curtailed and most SCO. The only refineries operating would be in Montreal from ME crude. Actually, Ab gas production would drop by about 5 BCFPD as the Montney would stop as there would be no market for Condensate. All Canadian gas exports would cease and in reality, we would import gas from the US to keep the northern tier refineries running.
Total capital for upstream costs (five trains of steam reformers, 190 wells and a high-pressure high-capacity CO2 distribution system) is about $72 billion dollars with annual operating costs of about 30 billion (mostly natural gas). This works out to a total cost per kg of $1.67 which is in line with published numbers.
So, we are off to races right. Wrong in the strongest terms. Before we get too excited, we have to look at the midstream and LDC level, because this is what the you and I will see after these costs are factored in.
IN the next installment I’ll outline what it means to pivot. On a personal level be prepared to shell out $7,500 for a hydrogen furnace.