A Laboratory Study of CO2 Interactions Within Shale and Tight Sand Cores - Duvernay, Montney and Wolfcamp Formations

Abstract

The most commonly used technology for development of unconventional reservoirs is horizontal wells combined with large multi-stage hydraulic fracture treatments. However, even with these technological advancements, primary recovery factors are generally less than 10 percent of the hydrocarbon in place. Water is currently the primary fracturing fluid used in most commercial developments. There is growing interest in non-aqueous (e.g. CO2) fluid systems not only to reduce water usage, but to increase well productivity and recovery factors. Use of carbon dioxide (CO2) as a fracturing fluid and an enhanced oil recovery (EOR) agent is also attractive from an environmental point-of-view. Organic rich shale reservoirs can be targets for carbon storage, due to their high CO2 adsorptive abilities and multiple mechanisms for gas storage. Therefore, use of CO2 can have both economic (increased recovery) and environmental (sequestration) benefits. This laboratory study investigates the interactions of CO2 with various cores from three formations (Duvernay, Montney, and Wolfcamp). Multiple core plugs were prepared from each of the three reservoirs. The mineralogy of the samples was measured with x-ray diffraction (XRD), and total organic carbon (TOC) and thermal maturity were determined with a SRA (Source Rock Analyzer). Porosity was also measured under as-received conditions and cleaned and dried conditions with a helium pycnometer. For each sample, its initial baseline permeability to helium was tested under a full cycle of net confining pressures (1,500 psia → 4,500 psia → 1,500 psia) with pressure steps of 1,000 psia using the pressure pulse-decay method. Subsequently the sample was vacuumed for 12 hours, and was then soaked with CO2 for more than 48 hours. Afterwards, the permeability to CO2 was measured under another cycle of confining pressures. Finally, the sample was vacuumed again and the regain permeability to helium was measured. Results indicate that the permeability to helium is generally recovered after CO2 soaking stages for tight-sand samples (e.g., Montney) and may be elevated for some samples enriched in organic matter and clay minerals (e.g., Wolfcamp). Overall the study shows favorable interaction between rock and organic material and CO2, which supports the use of CO2 as a fracturing or EOR fluid in these three reservoirs.

A Literature Review of CO2, Natural Gas, and Water-Based Fluids for Enhanced Oil Recovery in Unconventional Reservoirs

“…Dissolution of organic content by CO 2 can increase permeability. Reynolds et al showed that in cases where the core samples contained high levels of organic matter, permeability increased after soaking in pressurized CO 2 . Adsorption of CO 2 in shale can decrease permeability.…”

“…Reynolds et al showed that in cases where the core samples contained high levels of organic matter, permeability increased after soaking in pressurized CO 2 . 167 Adsorption of CO 2 in shale can decrease permeability. Al Ismail et al 104,168 studied the effect of CO 2 adsorption on Utica and Permian Shale samples.…”

Comparison of CO2 and Produced Gas Hydrocarbons to Recover Crude Oil from Williston Basin Shale and Mudrock Cores at 10.3, 17.2, and 34.5 MPa and 110 °C

“…The associated goals of reducing greenhouse gas emissions and increasing oil recoveries have led to growing interest in injecting CO 2 and/or produced rich gas hydrocarbons for both gas storage and enhanced oil recovery (EOR). ,,− This interest has resulted in several recent pilot-scale injections of CO 2 and rich gas hydrocarbons into the Bakken, ,,, but experimental data needed to support successful field projects that compare these gases’ abilities to mobilize crude oil under relevant reservoir conditions are limited. Recently, CO 2 and various hydrocarbon gas minimum miscibility pressures (MMPs) were measured with crude oils produced from the Three Forks (TFs) and Middle Bakken (MB) intervals of the Bakken Petroleum System.…”

Hydrocarbon Recovery from Williston Basin Shale and Mudrock Cores with Supercritical CO2: Part 1. Method Validation and Recoveries from Cores Collected across the Basin

“…The success of miscible and immiscible CO 2 floods in conventional reservoirs, as well as the desire to store CO 2 , has led several authors to suggest its use for enhanced oil recovery (EOR) in tight oil plays including the Bakken Petroleum System based on experimental work − and simulations. − However, it is likely that the CO 2 flow patterns through the reservoir rock as occurs in conventional (i.e., permeable) reservoirs are not representative of the fracture-dominated flow that controls how injected EOR fluids move through tight hydraulically fractured systems like the Bakken Petroleum System. ,,, Thus, CO 2 injected into the Bakken Petroleum System is not likely to flow primarily through the rock matrix, as it does in a conventional reservoir flood but rather will flow primarily through the fractures as driven by the pressure gradient and around the rock matrix via the induced (or natural) fractures. Once the pressure gradient is reduced in the fractures, the bulk rock matrix holding the unproduced oil experiences a “bath” of CO 2 , where the CO 2 permeates by diffusion into the rock matrix and oil hydrocarbons diffuse out of the rock matrix into the bulk CO 2 in the fractures.…”