No abstract

There are a number of additional challenges in the development of high CO2 content gas fields. To meet the requirements of the Kyoto Protocol and Paris Agreement, an efficient means to deal with the produced CO2 such as re-injection into the reservoir for sequestration is required. With the intention of developing such high CO2 gas fields, PETRONAS has identified a trial candidate (X field) offshore Sarawak Malaysia, which is a carbonate gas field with 70% CO2 content and good potential to re-inject the produced CO2 into the field's aquifer zone. To study the feasibility of CO2 reinjection, PETRONAS R&D team are studying the effects of re-injected CO2 on the mineralogical and petrophysical properties of the reservoir and decided to incorporate Digital Core Analysis (DCA) into the case study. Although porosity determination and other petrophysical property characterisation using micro-CT images has been widely used for a number of years, there is still discussion about its accuracy and reliability. Based on previous internal studies, porosity determination via digital core analysis can be limited by the quality and resolution of micro-CT images collected and thus the capability of the image analysis software. This case study investigates accuracy and reliability of the use of contrast enhanced imaging practices and the use of the helical micro CT for porosity determination via Digital Core Analysis (DCA). PETRONAS adopted and optimized a contrast enhanced imaging methodology for use on 1-inch core plugs during scanning via a helical micro-CT and applied this as a case study to X field with the help of a technology partner to evaluated digital core analysis. In the same year, a commercially available image analysis software was launched, with such a DCA workflow in mind. Using this optimized methodology and the newly launched imaging software, the porosity values from DCA of the 1-inch core plugs show good correlation to the values from Routine Core Analysis (RCA) done on the same samples, with less than 1.5 porosity unit difference. In this case study, PETRONAS managed to compare the porosity obtained from DCA directly with porosity measured by RCA. This methodology will be used for porosity determination for wells or other regions of interest where limited samples or different sample sizes are not suitable for RCA.

PETRONAS is interested in monetizing X Field, a high CO2 carbonate gas field located in East Malaysian waters. Because of its location (more than 200 km from shore) and the preferable geological formation of the field, reinjection of produced CO2 back into the field's aquifer has been considered as part of the field development plan. To ensure feasibility, the PETRONAS R&D team has conducted a set of laboratory analyses to observe the impact of CO2 on the carbonate formations, through combining the use of static CO2 batch reaction experiments with advanced helical digital core analysis techniques. The analysis of two representative samples, from the aquifer zone is presented here. The initial state of the samples was determined through the use of theoretically exact helical micro computed tomography (microCT) techniques. The images were processed digitally to determine the porosity and calibrated with RCA to ensure the reliability of digital core analysis results. After scanning, both plugs were saturated with synthetic brine with similar composition as the fields' formation brine and aged with supercritical CO2 at reservoir temperature and pressure for 45 days. After 45 days, the aged core plugs underwent post reaction analysis using micro-CT scan and image processing software. Based on macroscopic observation, the core plugs showed no changes after aging with supercritical CO2 at high pressure and high temperature (HPHT) as per reservoir condition. However, analysing the high resolution micro CT images, the team was able to determine the changes in porosity before and after CO2 aging, which are around 1%.

Carbon capture and storage (CCS) provides a safe option to reduce carbon footprint on a large scale. Here, carbon dioxide (CO2) is stored in a reservoir formation, overlain by a seal with low permeability and high capillary entry pressure. Understanding CO2 migration through the seal is one of the main components to assess caprock integrity, thereby ensuring safe and long-term CO2 containment and storage. This research is a combined and detailed study of caprock porosity and permeability using core and well log data to overcome a major issue: Coring and logging operation are expensive, and rarely done in caprocks. Drill cuttings, however, are available as byproduct of all drilled wells. By studying the caprock porosity and permeability of a potential CO2 storage site, this study aims to develop porosity/permeability relationships which can be used as input to predict matrix migration and capillary leakage to ensure permanent storage of CO2. In this paper, drill cuttings and core samples, which were obtained from a potential CO2 storage site, went through a series of laboratory measurements to determine porosity and permeability. This includes mercury injection capillary pressure (MICP), unsteady state pulse decay permeability on plug samples, and poro-permeameter measurements on crushed samples. Preliminary results have shown that drill cuttings produce higher porosity and permeability values than core samples. Nevertheless, further analysis is needed to establish relationships and correlations between drill cuttings and core samples. By applying a multi-method approach, resulting in trends for porosity and permeability, we may be able to reduce the operational costs of coring by using drill cuttings as alternatives and at the same time help de-risking CO2 storage projects for wider scale of deployment.

Understanding CO2 migration through the reservoir seal is one of the main challenges in assessing caprock integrity, thereby ensuring safe and long-term CO2 containment and storage. The determination of seal rock properties using core sample analysis or well data is important to predict matrix migration of CO2 to minimise the risk of capillary leakage. However, core samples and continuous well log data of caprock sections are expensive and limited. This issue can potentially be resolved by using cuttings, that are readily available from drilling, with no additional coring cost. However, before drill cuttings can be used as an alternative, rock properties (porosity and permeability) values from drill cuttings must be correlated with rock properties from the preserved core data, for proof-of-concept purposes. In CO2 storage sites, the caprock zone is usually comprised of low permeability mudrocks. Due to the low permeability of caprocks with values <1 microDarcy (10−18 m2) conventional core analysis is insufficient to determine porosity and permeability. We here use helium pycnometry for porosity determination on plugs and mercury porosimetry on cuttings. Meanwhile, the selected methods for permeability determination is an unsteady-state technique for plugs, and pressure decay / GRI method for cuttings, as both methods can measure permeability down to or even below nanoDarcy (10−21 m2). For the proof-of-concept study, we expect a correlation between plug and cuttings permeabilities of R2> 0.8 as indication of success criteria, based on strong effect size from statistics point of view. Using data from literature, permeability and porosity values from core samples match the permeability from cuttings with R2 >0.9. The R2 value for cutting versus plug porosity is 0.95, which is satisfies the success criteria as well. The correlations show that porosity and permeability values from cuttings are comparable to values from plugs and can be used as an approximation for the uncored zone. This proof-of-concept study marks the beginning of a full fledge research study to establish porosity and permeability relationships in caprocks, which can be used as inputs in predicting CO2 matrix migration for safe geological storage of CO2. In addition, this approach can be applied to unconventional oil and gas studies, with potential cost saving from coring operations.