Revisiting the Appalachian Basin for CO2 Storage Resources Using the SRMS Classification Framework
9 Pages Posted: 16 Apr 2019 Last revised: 27 Oct 2020
Date Written: October 23, 2018
Abstract
One major challenge for the CCS is to understand if CO2 geological storage could be implemented at the scale of the climate change issue.
In 2017, the Storage Resource Management System (SRMS) was developed by the Society of Petroleum Engineers (SPE) with the support of the Oil and Gas Climate Initiative (OGCI) CO2 storage workgroup. SRMS is based on the concepts of the Petroleum Resource Management System (PRMS), also developed by the SPE, which provides a classification framework for oil & gas resources and reserves. The SRMS provides guidelines on how to classify CO2 storage resources within various storage categories. It is done based on the assessment level of confidence and maturity of the assessment. It also provides guidelines on how assess mature storage resources capacity, increasing its chance of commerciality and ultimately allow for operational deployment of CO2 geological storage.
The Appalachian Basin is a mature basin that contains oil, gas and coal resources and extends over an area of 50,000 km2. Despite it is well known for the reserves, it has been studied as a potential CO2 storage system. It is identified as one of the larges storage systems in North America. The basin was extensively exploited causing a large number of wells especially on Marcellus asset. For the volumetric estimation of CO2 sequestration, several formations were studied, especially Oriskany sandstone and Medina and Tuscarora Sandstone. Some of the analyses are probabilistic using stochastic variables in a Montecarlo method to determine the uncertainty in the storage volume.
The result of the review is that the Appalachian basin storage resources remain prospective resources, in the Play subcategory. An important point to be considered is to evaluate and quantify the storage capacity of the shales of this basin. Indeed, it is known that organic rich shales desorb methane while adsorbing CO2. Experiments performed in Marcellus shale show that those shales can adsorb 4 times more CO2 than Methane. Consequently, if all of the methane absorbed for the shale could be displaced by CO2 the additional capacity of the shale could be of approximately 50 Gt. Engineering studies need to be performed in order to verify this numbers.
Two issues that can affect the storage capacity are: CO2 migration through connexion of shallow formation and the number of wells performed in the basin that can condition the injection strategy or the seal between formations.
The complexity of the basin is important with a fractured system. Several studies affirm that there are evidences of migrations from Marcellus formation to shallow aquifers. These evidences are recorded in the NE of Pennsylvania and the mechanics of migration are inferred faults. Gravity data suggest that some of these structures can possibly extended to the basement.
Some shale like Marcellus was used as a cap-rock and these well that are crossing the cap-rock can be potential conduits for the CO2 injected. Also they will determine the placement of the injection well for CO2.
Recommendations are finally provided in order to ensure compatibility with SRMS.
Keywords: Case studies, GHGT-14
Suggested Citation: Suggested Citation