Deep Direct Use Geothermal Energy in the North Dakota Clean Energy Transition Strategy

The geothermal heat in the Williston Basin is an energy giant that can provide sustainable, renewable, and ecologically sound heat and power for the state of North Dakota (ND). We have known of this resource for decades, but development has been delayed for reasons which can be summed as economic competition from existing fossil fuel energy sources. With the “seismic” shock of the Covid-19 pandemic reverberating through the state’s carbon-centric economy, the timing is ideal for acting quickly to develop this energy resource. Coincidentally, the State Energy Research Center (SERC) within the Energy & Environmental Research Center (EERC), has recently embarked on an analysis of ND’s energy future, and the availability and sustainability of resources for the state and the citizens of ND. Thus, the opportunity to examine the case for including geothermal energy in the strategy is at hand. The option we examine here is Deep Direct Use (DDU) geothermal energy, in multiple applications and in conjunction with Advanced Energy Storage technology. DDU can reduce and replace demand on energy supplies in two applications: direct use heat and electrical power. While in grid energy terms each DDU unit is relatively small, hundreds of these units would have a significant impact and merit consideration in the energy strategy. Realizing that DDU development is not currently market-driven, we are framing the analysis for potential early adopters and energy policy advisors based on a reference design and using that design to examine the project economics. The purpose of this paper is to get an early indication of whether the early stage project economics indicate “stop now”, or “proceed with caution”

Using Geothermal Energy to Reduce Oil Production Costs

The economic impact of the Covid-19 pandemic on the oil industry has been devastating. The decline in demand and price collapse have been particularly disruptive for shale oil extraction which is inherently more expensive than conventional operations. Survival and continuing operations will depend partly on reducing operating costs, and a ubiquitous and substantial cost in oil production is electrical power used primarily for pumping the wells. The Bakken in North Dakota play is particularly vulnerable because there is not an adequate electrical grid in the region. Many Bakken fields rely on generators burning propane, gasoline or diesel fuel at costs about $0.28 per kWh - four times grid costs. Shale plays have the unique characteristic of multiple wells per pad so that the total fluid available can be enough for coproduction of 10s to 100s of kW with an ORC on site. Bakken temperatures range from 100 °C where heat flow is low (≈50 mW m-2) and the Bakken is shallower on the eastern margin of the shale play to 140 °C where heat flow is higher (≈70 mW m-2) and the Bakken is deeper in the center of the basin. Previous analyses of the potential for coproduction were based on total field and large multi-well pad production volumes and did not address fluid flow per individual well. Analysis of heat loss with 2-D and 3-D models indicates coproduction is not feasible because fluids in Bakken wells lose too much heat during the slow 3-km transit to the surface. Water-rich carbonate rocks underlying the Bakken have higher temperatures and could generate several MW of power at local sites. Three scenarios for the higher power operations include: 1) Recompleting marginally economic existing oil wells in the overlying Lodgepole Formation and converting to water production; 2) Installing ORCs on the many water flood projects in the basin; 3) Drilling dedicated well fields for geothermal power production. After use in the ORCs, the hot waters could be used for low-cost space heating and further reduction of energy costs. An average submersible pump requires 16 kW, so, for example, if an ORC generated 160kW it could supply enough electricity to pump 10 wells

A Relook at Canada’s Western Canada Sedimentary Basin for Power Generation and Direct-Use Energy Production

The Alberta No. 1 Project, under the terms of Canada’s Federal government’s Emerging Renewable Power Program (ERPP), must produce 5MWe net. The goal of this study was to identify areas where three essential constraining conditions overlap; (1) the temperature gradient is sufficiently high that 120°C brines at depths of 4,500m or less are potentially available, (2) there are formations at the depths targeted with known high fluid flows, and (3) there is adequate existing infrastructure that supports low-cost power grid connection as well as a direct use application. A fluid temperature of at least 120oC is needed to profitably operate the plant. Temperatures below this require increasingly greater amount of fluids to be pumped and injected making them uneconomic. Three hundred liters per second (l/sec) of 120oC water is required to generate 5 MW net of electrical power with an Organic Rankin Cycle (ORC) binary plant. A depth cut off from a project economics perspective is about 4,500m for large diameter geothermal wells. Fortunately, these formations don’t need to be thick to supply these volumes of water to the well bore and thin permeable formations are expected to be laterally extensive in the regional layer cake (Western Canada Sedimentary Basin, WCSB) geology of Alberta. Thus, targeting known high fluid producing geologic units, rather than narrow faults is an important aspect of developing a geothermal project in the WCSB. Alberta No. 1 identified nine study areas to assess for geothermal potential. Of these, the Tri-Municipal Industrial Park (south of Grande Prairie) was determined to be the most suitable for both power production and development, followed by Edson (west-central Alberta). Other areas were identified as being most suitable for basement EGS to produce power, as well as direct use from shallower formations

A new database structure for the IHFC Global Heat Flow Database

Periodic revisions of the Global Heat Flow Database (GHFD) take place under the auspices of the International Heat Flow Commission (IHFC) of the International Association of Seismology and Physics of the Earth's Interior (IASPEI). A growing number of heat-flow values, advances in scientific methods, digitization, and improvements in database technologies all warrant a revision of the structure of the GHFD that was last amended in 1976. We present a new structure for the GHFD, which will provide a basis for a reassessment and revision of the existing global heat-flow data set. The database fields within the new structure are described in detail to ensure a common understanding of the respective database entries. The new structure of the database takes advantage of today's possibilities for data management. It supports FAIR and open data principles, including interoperability with external data services, and links to DOI and IGSN numbers and other data resources (e.g., world geological map, world stratigraphic system, and International Ocean Drilling Program data). Aligned with this publication, a restructured version of the existing database is published, which provides a starting point for the upcoming collaborative process of data screening, quality control and revision. In parallel, the IHFC will work on criteria for a new quality scheme that will allow future users of the database to evaluate the quality of the collated heat-flow data based on specific criteria

The Global Heat Flow Database: Release 2021

This data publication contains the compilation of global heat-flow data by the International Heat Flow Commission (IHFC; http://www.ihfc-iugg.org/) of the International Association of Seismology and Physics of the Earth's Interior (IASPEI). The presented data release 2021 contains data generated between 1939 and 2021 and constitutes an updated and extended version of the 2012 IHFC database release (IHFC 2012; later re-published as PANGAEA release: Global Heat Flow Compilation Group, 2013). The 2021 release contains 74,548 heat-flow data from 1,403 publications. 55% of the reported heat-flow values are from the continental domain (n ~ 40,870), while the remaining 45% are located in the oceanic domain (n ~ 33,678). The data are provided in csv and Excel formats. Compared to earlier compilations, which followed the structure defined by Jessop et al. (1976), the new data release was transformed to the recently redefined structure for reporting and storing heat-flow data in the Global Heat Flow Database (Fuchs et al., 2021). Therefore, the notation and structure of the database was adopted, transforming the database field entries defined after Jessop et al. (1976) to the new field structure. Old code notations are not continued and the dataset was cleaned for entries without reporting any heat-flow value. Although successfully transformed, this release marks an intermediate step as the majority of the newly defined database fields have not been filled yet. Filling these fields, checking the existing entries and assessing the quality of each entry are the aim of the upcoming Global Heat Flow Data Assessment Project, for which this data set provides the basis. Consequently, we kindly ask the user to take notice that the current release still suffers similar problems as previously published compilations in terms of data heterogeneity, documentation and quality