Real-Time Evaluation of CO2 Production and Sequestration in a Gas Field
Authors: Aschehoug Marie , Kabir C. Shah 
Published: May 2016

Production of substantial fraction of CO2 in any hydrocarbon-gas stream poses a significant challenge in terms of separation and sequestration. Both environmental concerns and economic incentives provide the operators to search for safe, cost-effective ways of disposing CO2.

This paper presents a case study where a pragmatic solution of CO2 separation at surface and its disposal in a saline aquifer occurs in close proximity to its source. A suite of both modern and classical analytical tools are used to understand production behavior of individual wells. This understanding is imperative because production volume is dictated by the ability to dispose of the associated CO2 volumes to honor the fault-activation pressure limit. The analytical tool kit comprising transient-PI, combined static and dynamic material-balance methods, rate-transient analysis, among others, paved the way for rapid assessment of both the producing gas reservoir and the saline aquifer receiving the CO2 stream.

The use of real-time data allowed a comprehensive assessment of in-place volumes for the source gas and the capacity of the aquifer. Injection of supercritical CO2 suggests that the terminal aquifer pressure has been reached by encountering less-than-expected storage volume and owing to lowering of fracture-pressure gradient. On-time learning has allowed the asset team to search for alternative CO2 disposal solutions to ensure continuous gas production from this field.

Introduction

The merits of sequestering greenhouse gas have been discussed widely in the literature (IPCC, 2007; NETL, 2007). The capture and subsequent sequestering of CO2 has attracted a great deal of interest across multiple disciplines within the oil and gas industry, as well as power and allied industries. Saline aquifers present the most realistic option for sequestration. Other options, including abandoned oil and gas fields, are limited owing to the proximity to the source issue. Some studies (Flett et al. 2007) have probed the feasibility of separation of CO2 from a natural gas stream to allow processing in a liquefied-natural gas or LNG plant. Research in the past (Ennis-King and Paterson, 2003) has emphasized formation of a CO2 plume in a saline aquifer and the attendant mass transfer. Flow simulation studies showed that the gas/water relative-permeability hysterisis effect (Flett et al., 2004a, b) and trapping (Kumar et al. 2004) are plausible mechanisms for storage.

Mineralization of rocks owing to formation of carbonic acid was postulated as yet another storage mechanism. However, the mineralization process is thought to be a very slow process requiring thousands of years (Bachu et al., 1994; Preuss et al., 2003). The Flett et al. (2007) study concluded that the migration of a CO2 plume takes a very long time to equilibrate and that most shales are capable of trapping it. Most of these studies focused on sandstones. In carbonates, experimental studies showed that the pore characteristics change with CO2 injection and that improved injectivity is tied to formation of preferential channels or wormholes (Izgec et al. 2008a). Although commercial simulators may be used in modeling CO2 sequestration, changes in rock properties owing to fluid-rock-CO2 interactions may be hard to capture without experimental data, as Izgec et al. (2008b) have shown.

The study of Ehlig-Economides and Economides (2010a) suggested that injection of supercritical CO2 is tantamount to injecting liquid into a closed, liquid-filled saline aquifer. Using standard analytical treatment to model the behavior of such a system, they concluded that the volume of injected fluid cannot normally exceed 1% of pore space. The notion of a closed system generated a lot of discussion (Cavanagh et al., 2010; Ehlig-Economides and Economides, 2010b). Although the national energy technology laboratory (NETL) have reported (2011) a few worldwide CO2 injection projects, lack of engineering data in the public domain do not allow objective assessment.