Implication of mineralogical and petrophysical property changes to mechanical integrity of reservoir and caprock for safe CO2 storage
Abstract
This thesis is studying the re-injection of CO2 into the same reservoir it originates from.
The reservoir is the S Field, Sarawak Basin, offshore Malaysia, and contains
contaminated natural gas with ~30% methane and ~70% carbon dioxide. The re-injection, following separation of the CO2 on the platform, is incorporated in the field
development plan for adherence to the Paris Agreement and Malaysia’s vision of net
zero-carbon emissions by 2050. The in-situ CO2 storage strategy in this offshore
Miocene formation is associated with heterogeneous carbonates and extreme reservoir
conditions (temperature ~150°C, pressure ~34 MPa), requiring an extensive assessment
as well as advanced technology solutions. The main objectives of this study are to firstly
reduce subsurface CO2 storage risks for the S Field through improved prediction and
advanced understanding of fluid-rock interactions. Secondly, and strongly interlinked
with the first point, is to provide a systematic evaluation of the geological, including
geochemical and geomechanical, properties at different scales. This study characterises
reservoir and caprock properties and investigates CO2-water-rock (CWR) interactions
through experimental and modelling approaches. Findings from both laboratory and
modelling studies are used for risk assessment for CO2 storage in the S Field. An
integrated experimental program was developed to evaluate reservoir and caprock
characteristics and their geochemical, geomechanical, mineralogical, and petrophysical
analyses during CWR. For the CWR interaction study, carbonates and caprocks were
reacted with CO2 saturated brines for up to 35 days and six months respectively, under
reservoir pressure and temperature conditions. The samples used for all experiments
were core samples from a recent appraisal well, and synthetic brine was formulated
using the actual reservoir brine composition. Sensitivity analysis for CWR interaction to
quantify mineralogical changes was performed by geochemical modelling using
PhreeqC. The carbonate formation has heterogenous properties with the highest porosity
(40%) and permeability (3000 mD) observed in the gas zone. The mineralogy in the gas
zone is dominated by calcite (80-90 wt %), while mineralogy in the aquifer zone is co-dominated by calcite (50%) and dolomite (40%). The differences in the petrophysical
properties and mineralogical composition are due to diagenesis and differences in
depositional environment. These differences also influence the geomechanical
properties, resulting in stronger carbonates in the aquifer zone compared to the gas
zone. The highest peak stress in the stress-strain curve for aquifer zone samples is 40
MPa with static Young’s modulus is 9 GPa compare to 16 MPa of peak stress in gas
zone samples and Young’s modulus of 5 GPa. The primary caprock (Seal A), composed
of Miocene mudrocks and siltstones has proven to be an effective seal with a thickness
of ~500m. The measured porosity is in the range of 2-10% and permeability of 0.5 µD.
The main mineral components of Seal A are illite and quartz; some minor amounts of
swelling clays (smectite) have been observed. Minimal changes in both mineralogy and
petrophysical properties were observed in both reservoir carbonates and caprock shale
after exposure to scCO2. Geomechanical properties such as strength and stiffness were
similar after exposure to scCO2. Based on the results, the risk assessment shows a low
impact with negligible action required to conduct CO2 storage in the S Field. The data
derived from the laboratory works were used to develop new and improved correlations
on subsurface characterization, specifically in carbonate reservoirs with similar
heterogeneity and depositional environments. For example, value creation from the
integrated subsurface characterization is the new correlation between porosity-permeability and the relationship of porosity and rock strength in carbonate formation.
In addition, findings from the laboratory and sensitivity studies can be used as input for
reservoir model calibration and 3D coupled modelling for future CO2 storage
development plans in the S Field. Applications of the developed methodology
combining various laboratory work in this study have proven satisfactory in studying
the identified subsurface uncertainty for CO2 storage development. It had been used as a
base methodology for other eight further potential CO2 sites in hydrocarbon fields
offshore Malaysia. The unique findings from the extensive and long duration of CO2-
water-rock interaction experiments at the extreme pressure and temperature conditions
in this study can be a reference or analogue data to other hydrocarbon fields with similar
conditions. On top of that, the comprehensive geological risk assessment using bow tie,
risk matrix, and heat map developed from this study can guide other high CO2 field
development plans in carbonate reservoirs.