Estimating decades-long trends in petroleum field energy return on investment (EROI) with an engineering-based model

Energy Return on Investment of Major Energy Carriers: Review and Harmonization

Net energy, that is, the energy remaining after accounting for the energy “cost” of extraction and processing, is the “profit” energy used to support modern society. Energy Return on Investment (EROI) is a popular metric to assess the profitability of energy extraction processes, with EROI > 1 indicating that more energy is delivered to society than is used in the extraction process. Over the past decade, EROI analysis in particular has grown in popularity, resulting in an increase in publications in recent years. The lack of methodological consistency, however, among these papers has led to a situation where inappropriate comparisons are being made across technologies. In this paper we provide both a literature review and harmonization of EROI values to provide accurate comparisons of EROIs across both thermal fuels and electricity producing technologies. Most importantly, the authors advocate for the use of point-of-use EROIs rather than point-of-extraction EROIs as the energy “cost” of the processes to get most thermal fuels from extraction to point of use drastically lowers their EROI. The main results indicate that PV, wind and hydropower have EROIs at or above ten while the EROIs for thermal fuels vary significantly, with that for petroleum oil notably below ten.

Carbon implications of marginal oils from market-derived demand shocks

Expanded use of novel oil extraction technologies has increased the variability of petroleum resources and diversified the carbon footprint of the global oil supply¹. Past life-cycle assessment (LCA) studies overlooked upstream emission heterogeneity by assuming that a decline in oil demand will displace average crude oil². We explore the life-cycle greenhouse gas emissions impacts of marginal crude sources, identifying the upstream carbon intensity (CI) of the producers most sensitive to an oil demand decline (for example, due to a shift to alternative vehicles). We link econometric models of production profitability of 1,933 oilfields (~90% of the 2015 world supply) with their production CI. Then, we examine their response to a decline in demand under three oil market structures. According to our estimates, small demand shocks have different upstream CI implications than large shocks. Irrespective of the market structure, small shocks (-2.5% demand) displace mostly heavy crudes with ~25-54% higher CI than that of the global average. However, this imbalance diminishes as the shocks become bigger and if producers with market power coordinate their response to a demand decline. The carbon emissions benefits of reduction in oil demand are systematically dependent on the magnitude of demand drop and the global oil market structure.

Detailed Energy Accounting of Electrical Submersible Pumping Systems

The concept of energy return on investment (EROI) is applied to a set of electrical submersible pumps (ESPs) installed on a small offshore platform by conducting a detailed energy accounting of each ESP. This information is used to quantify the energy losses and efficiencies of each ESP system as well as the EROI of the lifting process (EROILifting), which is derived by dividing the energy out of each well, which is the chemical energy of the crude oil produced, by the energy consumed by each ESP system and by the surface equipment used to dispose of the well’s produced water. The resulting EROILifting values range from 93 to 565, with a corresponding energy intensity range of 18.3 to 3.0 kWh/barrel of crude. The energy consumed by each well is also is used to calculate the lifting costs, which is the incremental cost of producing an additional barrel of crude oil, which range from 0.64 to 3.90 USD/barrel of crude. The lifting costs are entirely comprised of procured diesel fuel, since there is no natural gas available on the platform to be used as fuel. Electrical efficiencies range from 0.60 to 0.80, while Hydraulic efficiencies range from 0.12 to 0.56. The overall ESP efficiencies range from 0.09 to 0.39, with the largest losses occurring in the hydraulic system, particularly within the ESP pump itself. Improvement of pump efficiencies is the only practical option to improve the overall ESP system efficiencies. Other losses within the electrical and hydraulic systems present few opportunities for improvement.

Modeling impacts of sea-level rise, oil price, and management strategy on the costs of sustaining Mississippi delta marshes with hydraulic dredging

Over 25% of Mississippi River delta plain (MRDP) wetlands were lost over the past century. There is currently a major effort to restore the MRDP focused on a 50-year time horizon, a period during which the energy system and climate will change dramatically. We used a calibrated MRDP marsh elevation model to assess the costs of hydraulic dredging to sustain wetlands from 2016 to 2066 and 2016 to 2100 under a range of scenarios for sea level rise, energy price, and management regimes. We developed a subroutine to simulate dredging costs based on the price of crude oil and a project efficiency factor. Crude oil prices were projected using forecasts from global energy models. The costs to sustain marsh between 2016 and 2100 changed from $128,000/ha in the no change scenario to ~$1,010,000/ha in the worst-case scenario for sea level rise and energy price, an ~8-fold increase. Increasing suspended sediment concentrations, which is possible using managed river diversions, raised created marsh lifespan and decreased long term dredging costs. Created marsh lifespan changed nonlinearly with dredging fill elevation and suspended sediment level. Cost effectiveness of marsh creation and nourishment can be optimized by adjusting dredging fill elevation to the local sediment regime. Regardless of management scenario, sustaining the MRDP with hydraulic dredging suffered declining returns on investment due to the convergence of energy and climate trends. Marsh creation will likely become unaffordable in the mid to late 21st century, especially if river sediment diversions are not constructed before 2030. We recommend that environmental managers take into consideration coupled energy and climate scenarios for long-term risk assessments and adjust restoration goals accordingly.