Oil & Gas, Present & Future
- November 7, 2018
- 3306 views
My posts are made to Energy Central. This is not called electric utility central or anything else, it is Energy Central. Today the primary sources of energy for mobility and electric utilities come from the oil and gas industry. Thus I would be remiss if I didn't write about these.
The following paper is on the current use of energy, future changes, and possible evolution in the oil and gas industry.
The oil and gas industry is spread out over two North American Industrial Classification System (NAICS) sectors: 21 (Mining, Quarrying, and Oil and Gas Extraction) and 32 (31-33 are "Manufacturing"). Also, processing primary petroleum products is spread out over two facilities: oil-and-gas field for extraction and refineries for producing most final products, so we will address each of these two facilities separately.
2.1.Oil and Gas Extraction
This industry (primarily NAICS 211, but also 213111 & 213112) has a combined revenue of approximately $381 Billion per year (2012). Oil and gas extraction deals with all of the processes that occur in the oil & gas field including exploration, drilling, extraction and well shut-in/well abandonment.
This industry frequently has boom and bust cycles, and went through one and a half of these cycles, with rapid expansion from 2002 to 2012, contraction from 2012 to 2016, and has been slowly expanding since 2016. The value-of-shipments grew over 11.5% per year between 2002 & 2012. From 2013 until 2016 the price of crude-oil dropped from around $100 per barrel to around $50 per barrel triggering a contraction. Recent (2018) pricing is in the $60 to $80 per barrel range.
Note that the time-frame we will use for the growth evaluation is 2002 to 2012, as statistics are currently not available for more recent years.
Note that pre-pipeline processing is generally included in the extraction process, although rarely non-associated gas (gas extraction that is not associated with oil extraction) can sometimes be directly sent to a compression station and into the pipeline without any processing.
Production figures for the top 10 states and recent years are seen below.
Crude Oil Field Production (Thousand Barrels per Day)
Annual Dry Natural Gas Production (MMcf)
Oil and gas extraction is primarily in low energy-cost states, but California and Alaska are the third and fourth largest states in oil production. High utility energy-cost is less important because these industries use a large percentage of self-generation and have a strong incentive for future self-generation. High energy-cost states only have 3.9% of facilities.
In 2015 there were 111 firms with more than 500 employees. These firms had 1,412 facilities, each of which had an average of 59 employees. It is estimated that 200 of these facilities would be considered large (over 250 employees each).
Although a value for energy cost is assigned (3.1% of revenue), the energy use of this industry is uncertain since the product produced is potentially an energy fuel, and is frequently used during the production process (before it goes into a transmission pipeline) to generate process heat and/or electricity. The energy- value was based on the document referenced and an estimate made for Unit Energy Consumption of 1,740 BTU/2005-dollars. When multiplied by revenue this yields 0.66 Quad energy use valued at about $12 Billion, or 3.1% of revenue.
An increasing number of producing oil fields are turning to cogeneration, particularly if they need process steam. In areas that have very viscous oil, the steam is injected into the oil-bearing stratum to heat the oil and reduce its viscosity. For this reason steam turbines are used to generate electricity. The steam is generated with boilers fired with crude oil or unprocessed gas from the field. An alternative to this is to use combustion turbines to generate the electricity with the hot exhaust fed into a boiler to generate steam. The CHP database has 101 CHP facilities with 2,766 MW total capacity.
Self-generation can be used to monetize stranded gas reserves. About 25% of natural gas is associated with crude oil extraction. This gas is occasionally stranded, meaning it is not economical to process the gas, possibly because the volume is too low or the oil field is not close to a gas pipeline. Although previously stranded gas was flared, it is more common to re-inject it today if it can’t otherwise be used.
2.2.Gas Processing and Oil Refineries
This category includes NAICS 324110, and part of 213112. Revenue is over $800 Billion per year (2012, oil refineries only). The value of shipments has grown rapidly, having grown over 15% per year between 2002 and 2012 (oil refineries – see comments below regarding gas processing) and is currently in decline.
A couple of introductory comments will clarify the relationship between extraction and processing. As pointed out in the prior section, the processing of oil and gas starts in the field. With oil, the pre-pipeline processing consists of:
- Separating all gasses from crude (including methane/natural gas)
- Filtering out any solid material
- Removal of water, including the breaking up of oil-water emulsions
The story with gas is a bit more complex. A small percentage of non-associated gas (gas that is not mixed with crude oil) can be put directly in the pipeline to the gas processing plant, and an even smaller percentage is suitable for the transmission pipeline (suitable for end-use). A large majority of non-associated gas and all associated gas must be processed prior to being compressed for pipeline transmission to final processing plants. In many cases, especially with non-associated natural gas, “skid-mount plants” are installed in or near the gas field to dehydrate and decontaminate raw natural gas into acceptable pipeline-quality gas for direct delivery to the transmission pipeline. These compact skids are often specifically customized to process the type of natural gas produced in the area and are frequently inexpensive compared with transmitting the gas to a distant large processing plant.
The elements of gas processing include:
- Gas-oil separation (if required, always done in the gas field)
- Condensate separation (separation of most water and natural gas liquids as described below)
- Dehydrate (removal of most remaining water, always done in the gas field)
- Remove contaminants: hydrogen sulfide, carbon dioxide, etc. (always done in the gas field)
- Nitrogen extraction
- Demethanizer: removes pure methane (natural gas) from remaining hydrocarbons (natural gas liquids)
- Fractionator: separates natural gas liquids into ethane, propane, pentanes and natural gasoline (a hydrocarbon mixture consisting of pentanes, isopentane and hexanes)
The natural gas liquid fractions are piped, trucked and/or shipped by rail-cars to refineries or other end-users.
In 2012 there were 517 natural gas processing plants capable of processing about 65.5 Billion cubic feet of natural gas a day. Each of these can either be co-located with a gas/oil field, a pipeline compressor station, or be a stand-alone facility. Also, the functions performed in gas processing can be distributed to where only two or three of these are performed near the well-head before transmission to a centralized processing plant.
Because of the above distributed processes and inconsistent bundling of energy consumption (and electric and heat production in some cases), energy use in gas processing will not be addressed further in this paper.
Oil Refineries (NAICS 32411), on the other hand, have clearly defined roles in the product value chain. Virtually all crude oil eventually goes to a refinery (except for a very small percentage that is directly used for heat, mechanical drives or electric self-generation in the oil field). All refineries are large centralized facilities. In 2016 there are 139 operating refineries with total capacity of 18,317,036 barrels per calendar-day.
Almost half of refineries (by revenue) are in Texas and Louisiana. The good news is that California is ranked number three, and about 17% of refineries are located in high energy-cost states. High utility energy cost is less important because of the extensive self-generation and use of waste-to-energy.
Refining oil is the second most energy-intensive industry in the U.S., and accounted for about 7 percent of total U.S. energy consumption in 2002. The U.S. petroleum refining industry consumed the energy shown in the table below for heat and power. About 64% of the energy sources shown in this table were provided by fuels that are byproducts of the refining process.
In 2010 oil refineries used about 6 Quads of energy, using the table above and assuming about 35% of this energy was purchased, this was 2.1 Quads with a value of about $37 Billion, or about 4.6% of revenue.
Self-generation using combined heat and power (CHP or cogeneration) is a major source of electricity for US Refineries. In 1999 CHP accounted for almost 35% of all electricity used by refineries.
There are opportunities for improved energy efficiency at oil refineries on the order of 10% to 20%. Major energy efficiency improvements can be achieved in utilities (30%), fired heaters (20%), process optimization (15%), heat exchangers (15%), motor and motor applications (10%), and other areas (10%). Optimization of utilities, heat exchangers, and fired heaters are the most cost-effective.9
Although the subject of this paper was in my queue to write, it was bumped to the top when I discovered a report from Wood Mackenzie. I saw a review of this report in Greentech Media (GTM, Wood Mackenzie is the parent company of GTM). I've referenced the article below and will briefly summarize it in this section.
The main proposition of this article and report was that by 2035 renewables will likely meet 20 percent of global power demand, up from today's 7 percent. The combination of wind, solar and electric vehicles will displace about 100 billion cubic feet of oil per day, creating an “unstoppable” shift for companies and countries around the world.
After that, adoption of renewables accelerates even faster — with wind, solar and electrified transport becoming “the default choice across many energy systems around the world.”
A year after the 2035 inflection point, the Wood Mackenzie report forecasts a peak in oil demand, with electric motors accounting for 15 to 20 percent of all miles traveled in buses, cars, trucks or on bicycle. Electric vehicles could eliminate the use of 6 million barrels of oil per day by 2040.
Wood Mackenzie also notes the inflection point could come earlier as policy gets more ambitious, or if technologies such as advanced energy storage and microgrids take root earlier than current projections.
So the oil and gas industry is getting a triple-whammy:
- The development wind and photovoltaic (PV) are displacing fossil-fueled electric generation.
- The development of electric vehicles (EVs) and battery energy storage systems (BESS) are mutually accelerating both products' development and driving battery prices lower.
- Plunging prices of BESS, wind and PV in the long term have the potential to completely displace all types of non-renewable generation and provide low-price electric energy that displace petroleum fuel from the transportation sector.
So what is the oil and gas industry to do? Clearly they need to evolve their current business model. The first question is: what are they really good at?
- Building large pipeline transmission and distribution networks for liquids and gasses.
- Processing complex liquids and gasses and producing other liquids and gasses that can be used by consumers and other industries.
Certainly the above expertise can be evolved in multiple directions that do not involve petroleum. I touched on this briefly in section 3.1 of the paper linked below, and will expand further.
4.1.Power Generation: A Unique Value Proposition
Solar and wind are low-greenhouse gas (GHG) electric generation sources. They are not zero GHG sources, because some GHG is produced in their manufacture and maintenance. There is a way to produce net-negative-GHG power as I will describe below, but first I must take a side-step.
Refuse collection where I live is contracted to a private company (Livermore Sanitation). There are three containers: one for most recyclables (single-stream), one of landfill trash, and one for "green waste". I would guess that most trash collection in urban and suburban California and many other areas follow a similar practice. The green waste container is the largest and contains yard clippings, food waste and other organics that are suitable for composting.
Green waste is also suitable for anaerobic digestion. Which creates biomethane. And, as you can probably deduce, there is a huge amount of green waste. If this is processed efficiently it will produce a huge amount of biomethane. By the way, the other name for biomethane is renewable natural gas, and it's really no different from any other natural gas.
So now you're thinking: "OK, so the oil and gas industry has found a source of gas, but what about this net-negative-GHG business?
Take the biomethane, pipe it to an existing state-of-the-art combined-cycle power plant (no modifications required) and produce power, plus exhaust. Take the exhaust and run it through a skid-mounted carbon dioxide (and any other GHGs) separation plant. This plant is much like the "skid-mount (gas processing) plants" described in section 2.2 above. See section 3.2.3 in my earlier "Concrete Greenhouse" paper (linked below) for one CO2 separation process.
In order to produce the contents of the green waste (a large majority of which is plant-based), carbon dioxide is absorbed from the atmosphere. None of the processes to produce bio-methane, convert this to power and separate the GHGs from the exhaust is 100% efficient, but if any resulting GRGs from these processes are (for instance) sequestered in geologic formations, the whole process should be at least slightly GHG-negative. The key is to capture any significant GHGs resulting from any of these sub-processes, and also sequester them.
Geologic sequestration will involve other oil and gas industry skills. Understanding underground geological formations well enough to know were GHGs can be permanently sequestered, and of course, drilling. The oil and gas already uses CO2 injection to rejuvenate depleted oil fields, so there is really no learning curve here.
There are two pathways to very-low GHG mobility electrification (plus very low GHG electricity) and hydrogen. It currently looks like electrification will be the winner in most transportation segments, either directly (rail) or via battery electric vehicles (roadway vehicles). However, there may be a role for hydrogen in some segments as described below.
The oil and gas industry will already have a piece of the electric generation market as described in the prior subsection (if they follow this path). If hydrogen has a piece of the GHG solution, they may also have a piece of this market.
Biomethane to hydrogen: Let us assume that biomethane completely displaces petro-methane over several decades. Most planners looking at how our economy will evolve to eliminate all GHG emissions agree that residential and small commercial use of natural gas will probably continue to the end of this process. Thus "natural gas" (transmission and) distribution networks will continue to be widely available. The method to evolve natural gas use from "somewhat low GHG" to "very low GHG" may involve changing what flows through these pipelines to biomethane.
Currently a large percentage of hydrogen used for industry and fuel cells (including fuel-cell vehicles) is refined by reforming methane. Thus any location that requires hydrogen could create this on-site through biomethane reformation. A product of this reformation process in CO2, and it may be that some larger hydrogen reformers are eventually obliged to inject this GHG into a GHG-gathering network to be sent off for sequestration.
Aviation: The toughest application for battery-electric powertrains are airplanes. The short-term solution for this are jet-biofuels (go through the link below). These are currently made using bio-alcohol, and the processes for making this currently are very inefficient, and also use potential food products. There is reasonable hope that more efficient processes will be developed in the next decade or two given push for renewable fuels. See the second link below for a thorough treatment of cellulosic ethanol.
And by the way, I'm reasonably sure that the oil and gas industry can find a major role in producing renewable jet fuel (and, by the way, renewable gasoline for people that insist on hanging on to internal-combustion-powered cars).
There are many industries that use various petroleum products as feedstocks to their end-products, these include those that come from natural gas production, those that come from crude oil refining, and those that are compounded by the oil and gas industry from the former ingredients (see section 2.2). The oil and gas industry will continue supplying these for many decades, and ultimately will define biologically derived substitutes for a large majority of these.
At the end of the day, there still may be a small "oil and gas" sub-industry producing specialized substances from geo-derived oil and gas. The remaining industry hopefully will evolve, perhaps as described above.
 US Energy Information Administration (EIA), http://www.eia.gov/dnav/pet/pet_crd_crpdn_adc_mbblpd_a.htm
 U.S. Census Bureau, 2013 SUSB Annual Datasets by Establishment Industry, U.S. & states, NAICS, detailed employment sizes (U.S., 6-digit and states, NAICS sectors), http://www.census.gov/data/datasets/2013/econ/susb/2013-susb.html
 1 Quad = 1 quadrillion BTUs = 293,071,083 MWh. For the purposes of this paper will assume the cost of energy is $.06 per kWh or $17.6 Billion per Quad.
 U.S. Energy Information Administration, Office of Integrated and International Energy Analysis, U.S. Department of Energy, “Annual Energy Outlook 2014”, https://www.eia.gov/todayinenergy/detail.php?id=16171
 Energy Information Administration, Natural Gas Annual Respondent Query System, http://www.eia.gov/cfapps/ngqs/ngqs.cfm?f_report=RP9&f_sortby=&f_items=&f_year_start=&f_year_end=&f_show_compid=&f_fullscreen=
 US Energy Information Administration, http://www.eia.gov/dnav/pet/pet_pnp_cap1_dcu_nus_a.htm
 Joan Pellegrino, Sabine Brueske, Tracy Carole, and Howard Andres of Energetics, Incorporated, Columbia, Maryland, “Energy and Environmental Profile of the U.S. Petroleum Refining Industry”, Prepared for the U.S. Department of Energy, 2007, https://www.energy.gov/sites/prod/files/2013/11/f4/profile.pdf
 Emma Foehringer Merchant, Greentech Media, "Energy Transition to Reach ‘Point of No Return’ by 2035", October 22, 2018, https://www.greentechmedia.com/articles/read/energy-transition-to-reach-point-of-no-return-by-2035?utm_medium=email&utm_source=Storage&utm_campaign=GTMStorage#gs.QHEGNDM