Floating production systems versus subsea tiebacks: the costs?

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.

Fully subsea offshore projects: the 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.

Power from Shore: the economics?

We model the economics of powering an oil platform from shore, using cheap renewable power instead of traditional gas turbines. This can lower upstream CO2 emissions by 5-15kg/bbl, or on average, around 70%; for a base case cost of $50-100/ton.

Our numbers are derived from reviewing technical papers, plus ten prior projects (mostly in Norway), which are tabulated in the data-file, including capex figures (in $M and $/W) where disclosed.

The costs of CO2 abatement can be flexed by varying inputs to the model, such as project size, gas prices, power prices and carbon prices.

 

CO2 Intensity of Oilfield Supply Chains

This data-file calculates the CO2 intensity of oilfield supply chains, across ten different resources, as materials are transported to drilling rigs, frac crews, production platforms and well pads.

Different resources can be ranked on this measure of supply chain CO2-intensity: such as  the Permian, the Gulf of Mexico, offshore Norway, Guyana, pre-salt Brazil and Middle East onshore production (chart above).

Underlying the calculations are modeling assumptions, for both onshore and offshore operations, each based on c15 input variables. You can change the inputs to run your own scenarios, or test the most effective ways to lower supply-chain CO2.

Hybrid horizons: industrial use of batteries?

Gas and diesel engines can be particularly inefficient when idling, or running at 20-30% loads. At these levels, their fuel economy can be impaired by 30-80%. This is the rationale for hybridizing engines with backup batteries: the engines are always run at efficient, 80-100% loads, including to charge up the batteries, which can better cover lower intensity energy needs.

Hybrid passenger cars are the best known example, since Toyota re-introduced them in the late 1990s. c25-30% energy savings are achieved, including through engine down-sizing and regenerative breaking

Industrial applications are also increasingly taking hold as battery costs come down, achieving even higher, 30-65% energy savings. This data-file summarizes a dozen examples, from oil and gas, marine, construction and even the machinery at LNG plants.

Northern Lights CCS: the economics?

We have modeled out simple economics for Northern Lights, the most elaborate carbon capture and storage (CCS) scheme ever proposed by the energy industry (Equinor, Shell, TOTAL).

The project involves capturing industrial CO2, liquefying it, transporting it in ships, receiving it onshore in Norway, piping it 110km offshore, then injecting it 3,000m below the seabed. Phase 1 will likely sequester 1.3-1.5MTpa, with potential expansion to 5MTpa.

Our conclusion is that Phase 1 will be expensive. However, much of the infrastructure “scales”. So phase 2 could cost 35% less, bringing the “carbon storage” component to below Europe’s carbon price. This could be promising if combined with next-generation carbon separation or decarbonised gas technologies, to lower the “carbon capture” component.

Our economic estimates can be flexed in the ‘simple model’ tab. Underlying cost calculations are substantiated in the ‘Notes’ tab.

Development Concepts: how much CO2?

This data-file quantifies the costs and CO2 emissions associated with different oilfield development concepts’ construction materials.

We have tabulated c25 projects, breaking down the total tonnage of steel and concrete used in their topsides, jackets, hulls, wells, SURF and pipelines.  Included are the world’s largest FPSOs, platforms and floating structures; as well as new resources in shale, deepwater-GoM, Guyana, pre-salt Brazil and offshore Norway.

Infill wells, tiebacks and FPSOs make the most efficient use of construction materials per barrel of production. Fixed leg platforms are higher, then gravity based structures, then FLNG, and finally offshore wind (by a factor of 30x).

 

Johan Sverdrup: Don’t Decline

Equinor is deploying three world-class technologies to mitigate Johan Sverdrup’s decline rates, based on reviewing c115 of the company’s patents and dozens of technical papers. This 15-page note outlines how its efforts may unlock an incremental $3-5bn of value from the field, as production surprises to the upside.

Johan Sverdrup: Economic Model

We have modelled the economics of Equinor’s Johan Sverdrup oilfield, using public disclosures and own estimates. Our model spans >250 lines of inputs and outputs, so you can flex key assumptions, such as oil prices, gas prices, production profiles and costs. In particular, we have tested the impact of different decline rates and recovery factors on the field’s ultimate value.

Offshore Capex for Technology Leaders?

Technology leadership determines offshore capex. Specifically, this data-file measures a -88% correlation coefficient between different Major’s offshore patent filings in 2018 and their projects’ capex costs.

The details: We have tabulated the number of Offshore Patents filed in 2018, across 25 leading Majors, from our sample of 3,000 patents. We have also tabulated a dozen, recent, offshore greenfields operated by these companies, which were sanctioned in 2017-19. Investments from Aramco, BP, Equinor, Exxon, Petrobras, TOTAL and Shell are included.

The lowest-cost  projects are not “easy oil”. The most economical project in the entire sample, at $17M/kboed, has a complex gas cap with a risk of asphaltene precipitation.  Also in the ‘Top 5’ are an Arctic greenfield, an ultra-deepwater carbonate with unusually high-CO2 and an ultra-high pressure deep-water field. Economical development depends on leading technology.

To see the projects included in the analysis, please download the data-file…

Copyright: Thunder Said Energy, 2022.