Offshore vessels: fuel consumption?

This database tabulates the typical fuel consumption of offshore vessels, in bpd and MWH/day. We think a typical offshore construction vessel will consume 300bpd, a typical rig consumes 200bpd, supply vessels consume 150bpd, cable-lay vessels consume 150bpd, dredging vessels consume 100bpd and medium-sized support vessels consume 50bpd. Examples are given in each category, with typical variations in the range of +/- 50%.

This data-file tabulates the typical fuel consumption for different types of offshore vesesel, across all of our research into the offshore and shipping industries.

Offshore construction vessels are especially used in the offshore wind industry, where installation costs for a large-scale wind project will average aroud $1,000/kW spread across 60-100 vessels during peak activity. The largest are offshore construction vessels which will tend to consume around 300bpd of fuel. This is also factored in our EROEI calculations for a wind turbine.

Cable lay vessels are also used in offshore wind and more broadly amidst the expansion of power grids and HVDC interconnectors. We think a typical cable lay vesel will consume 150bpd of fuel.

Offshore rigs also see a continued role in our energy balances, in order to provide 85Mbpd of long-term oil demand and 800 bcfd of long-term gas demand in our roadmap to net zero. A typical offshore oil rig consumes 200bpd of fuel. The numbers are lower for jack-ups and ultra-efficient drillships, but can be higher for larger and older semi-subs.

Elsewhere in our shipping research, we see the typical fuel consumption of a large container ship at 1400bpd, a bulk tanker at 420bpd and a LNG carrier at 270bpd.

The fuel consumption of dredging vessels and the fuel consumption of platform supply vessels (PSVs) are also covered in the data-file of offshore vessels’ fuel consumption.

Please download the data-file for additional datapoints into the fuel consumption of different ships, and individual data-points that led us to these numbers.

Wind power: energy costs, energy payback and EROEI?

Wind power energy paybacks

Wind power energy paybacks? This data-file estimates 3MWH of energy is consumed in manufacturing and installing 1kW of offshore wind turbines, the energy payback time is usually around 1-year, and total energy return on energy invested (EROEI) will be above 20x. These estimates are based on bottom-up modelling and top-down technical papers.

The average wind energy project has an energy intensity of 3MWH/kW, which is repaid after c1-year, for a total energy return on energy investment above 20x, over a 20-25 year operating life.

One observation from reviewing technical papers is that many have rough methodologies. Some are still basing numbers upon small, <1MW turbines, which are no longer representative. Conversely, others are incomplete, and have not fully captured materials costs.

Hence we have built up our own bottom-up estimates for the energy intensity of wind power, and the EROEI of wind turbines.

Our bottom-up estimates for the energy costs of wind turbines are based on a full bill of materials, economic models of those materials (e.g., glass fiber, carbon fiber, epoxies, steel, copper), data into the vessel days per turbine, and the fuel consumption of different vessels.

Our bottom-up estimates for wind power EROEI also captured power transmission, curtailment considerations and maintenance requirements.

The largest individual contributors to the up-front energy costs of wind turbines are transporting materials to the site (0.75MWH/kW), steel (0.6MWH/kW), other materials (0.3MWH/kW), large offshore vessels that install foundations and turbines (0.3 MWH/kW) and the tail of 20-40 smaller vessels that support offshore operations (data here).

The average CO2 intensity of wind turbines is suggested at 10-20g/kWh (0.01-0.02kg/kWh). This coheres with the technical papers that we reviewed, and our own bottom-up estimates.

Wind power energy paybacks will vary with individual project parameters, and we think that a realistic range for offshore wind projects is 15-30x EROEI.

The most important parameter is the location of the project, which will determine energy generated per year, but also transportation distances and steel requirements.

Comparable data for solar assets is linked here.

US CO2 and Methane Intensity by Basin

US CO2 and Methane Intensity by Basin

The CO2 intensity of oil and gas production is tabulated for 425 distinct company positions across 12 distinct US onshore basins in this data-file. Using the data, we can break down the upstream CO2 intensity (in kg/boe), methane leakage rates (%) and flaring intensity (mcf/boe), by company, by basin and across the US Lower 48.

In this database, we have aggregated and cleaned up 957 MB of data, disclosed by the operators of 425 large upstream oil and gas acreage positions. The data are reported every year to the US EPA, and made publicly available via the EPA FLIGHT tool.

The database covers 70% of the US oil and gas industry from 2021, including 8.8Mbpd of oil, 80bcfd of gas, 22Mboed of total production, 430,000 producing wells, 800,000 pneumatic devices and 60,000 flares. All of this is disaggregated by acreage positions, by operator and by basin. It is a treasure trove for energy and ESG analysts.

CO2 intensity. The mean average upstream oil and gas operation in 2021 emitted 10kg/boe of CO2e. Across the entire data-set, the lower quartile is below 3kg/boe. The upper quartile is above 13kg/boe. The upper decile is above 20kg/boe. And the upper percentile is above 70kg/boe. There is very heavy skew here (chart below).

The main reasons are methane leaks and flaring. The mean average asset in our sample has a methane leakage rate of 0.21%, and a flaring intensity of 0.03 mcf/bbl. There is a growing controversy over methane slip in flaring, which also means these emissions may be higher than reported. Flaring intensity by basin is charted below.

US CO2 intensity has been improving since 2018. CO2 intensity per basin has fallen by 17% over the past three years, while methane leakage rates have fallen by 22%. Activity has clearly stepped up to mitigate methane leaks.

(You can also see in the data-file who has the most work still to do in reducing future methane leaks. For example, one large E&P surprised us, as it has been vocal over its industry-leading CO2 credentials, yet it still has over 1,000 high bleed pneumatic devices across its Permian portfolio, which is about 10% of all the high-bleed pneumatics left in the Lower 48, and each device leaks 4 tons of methane per year!).

Most interesting is to rank the best companies in each basin, using the granular data, to identify leaders and laggards (chart below). A general observation is that larger, listed producers tend to have lower CO2 intensity, fewer methane leaks and lower flaring intensity than small private companies. Half-a-dozen large listed companies stand out, with exceptionally low CO2 intensities. Please consult the data-file for cost curves (like the one below).

Methane leaks and flaring intensity can also be disaggregated by company within each basin. For example, the chart below shows some large Permian producers effectively reporting zero flaring, while others are flaring off over 0.1 mcf/bbl.

All of the underlying data is also aggregated in a useful summary format, across the 425 different acreage positions reporting in to EPA FLIGHT, in case you want to compare different operators on a particularly granular basis.

Water injection at oil fields: the economics?

Costs of waterflooding at oil fields

This model captures the energy economics of a conventional waterflooding project in the oil industry, in order to maintain reservoir pressure and productivity at maturing oilfields.

Our base case calculations suggest strong economics, with 30% IRRs at $40/bbl oil on a project costing $2.5/boe in capex and $1/bbl of incremental opex.

Please download the data-file to stress-test parameters such as commodity prices, water injection rates, reservoir pressure, electricity prices and other economic assumptions.

Floating production systems versus subsea tiebacks: the costs?

FPSO costs versus subsea tiebacks

This model estimates the line-by-line costs of an FPSO project, across c45 distinct cost lines, in order to quantify the potential savings of a tieback or a ‘fully subsea’ development.

Our estimates drawing on four technical papers, as illustrated in the backup tabs of the model. For a full discussion, see our recent note ‘The future of offshore: fully subsea‘.

We estimate c$750M of cost savings for a tieback, and c$500M of cost savings for a fully subsea development, as compared against a traditional project with a traditional production facility.  Please download the model to see the different cost drivers, line-by-line.

Platform supply vessels: what contribution to CO2?

Contribution of PSVs to oil industry CO2

This data-model calculates the contribution of Platform Supply Vessels (PSVs) to an offshore oil and gas asset’s emissions profile, as measured in kg/boe.

Our base case estimate is 0.1kg/boe for a productive asset in a well-developed basin. The numbers can be increased c4x in a remote basin, or by another c4x for smaller fields, so emissions >1kg/boe are possible.

Initatives to lower these emissions by 10-20% through LNG-fuelling or hybridization are described in the final tab. They will likely save 0.01-0.02kg/boe from most PSVs and other supply vessels.

Fully subsea offshore projects: the economics?

Fully subsea project economics

This model presents the economic impacts of developing a typical, 625Mboe offshore  gas condensate field using a fully subsea solution, compared against installing a new production facility.

Both projects are modelled out fully, to illstrate production profiles, per-barrel economics, capex metrics, NPVs, IRRs and sensitivity to oil and gas prices (e.g. breakevens).

The result of a fully offshore project is lower capex, lower opex, faster development and higher uptime, generating a c4% uplift in IRRs, a 50% uplift in NPV6 (below) and a 33% reduction in the project’s gas-breakeven price.

Please download the model to interrogate the numbers and input assumptions.

Offshore wind costs are inflating?

Offshore wind costs not deflating

This data-file tabulates the capex costs of 35 offshore wind projects in the UK, with 8.5GW of capacity, which have been installed since the year 2000.

We model the incentive price for each project, i.e., the power price that is needed to earn a 10% levered but unsubsizided return. There is little evidence for deflation. Rather, breakevens appear to have risen at a 2.5% CAGR over the past decade.

Please download the data-file to interrogate the findings, or view the individual project parameters. Continued technical innovation is needed in the wind industry. We find new airship concepts could help deflate logistic costs.

Wind turbine manufacturers: market share over time?

Wind turbine manufacturers

This data-file tracks wind turbine manufacturers, their market shares and their margins over time. By 2022, fifteen companies account for 98% of global wind turbine installations. This includes large Western incumbents, and a growing share for Chinese entrants, which now comprise over half of the total market, limiting sector-wide operating margins to c3%.

By 2022, fifteen companies account for 98% of global wind turbine installations. This includes large Western incumbents, and a growing share for Chinese entrants, which now comprise over half of the total market.

The wind turbine market is relatively concentrated, with a Herfindahl Hirschman Index of c1,000. The market share of the top five wind turbine manufacturers is 55%.

Wind turbine manufacturers
Screen of wind turbine manufacturers

However competition, price pressure and cost pressure have kept margins low, averaging 5.7% over the past decade for Vestas, the largest turbine manufacturer in the world (chart below). We have produced similar charts for other turbine manufacturers as well.

Wind turbine manufacturers
Vestas Revenues and Margins

Other margin drivers? Wind is less economically competitive than solar and more prone to cost re-inflation (note here). The industry has also had to reinvent itself every 2-3 years with ever larger turbines, which creates ever greater engineering issues (note here).

Patent filings from traditional energy companies looking to break into the offshore wind sector are also tabulated in the final tab. This includes ABB, Aker, Alstom, Aramco, BP, Cameron, Chevron, Eni, Equinor, ExxonMobil, GE, OneSubsea, Saipem, Shell, Siemens, Subsea 7, Technip, TOTAL and Vestas.

Majors and Services Offshore Wind Technologies

Across our broader research, we have also screened patents from Siemens Gamesa, from Goldwind, and compiled other wind research, data-files and models.

Subsea Services: Patent Leaders?

Subsea Oil Service Patent Leaders

This data-file captures all the subsea-focused patents from ten of the largest subsea service providers around the industry, to quantify who has a technical edge (chart above).

The balance has been shifting. During the oil downturn, large, industrial conglomerates effectively halved their pace of technology development, while some subsea service companies accelerated (chart below).

The relative rankings are interesting. The data-file shows clear leaders in the categories such as subsea pumps, wellheads or umbilicals. Other areas are more competitive, with 2-3 companies vying for leadership in, flexible risers, subsea power or pipe-lay. One large subsea EPC screens as ‘Top 5’ on most categories, but is facing strong competion across the board.

Covered companies include: ABB, Aker, Cameron, FMC,  GE, OneSubsea, Saipem, Siemens, Subsea7, Technip.

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