Introduction
Carbon-conscious companies are looking to achieve carbon neutral or negative status by capturing and
sequestering their CO2 output through methods known as Carbon Capture and Storage (CCS). The goal
is to capture CO2 outputs from various sources and store the CO2 in deep saline reservoirs. The industrial
sources of CO2 range from power plants, landfills, and hydrocarbon operations to steel, cement,
ammonia, and ethanol plants. Before any CO2 is injected into the ground operators must document
compliance of federal, state, and local regulations to obtain permitting. A subsurface characterization
study is one of the main components of regulatory permitting. A local geologic study within the CO2
source area identifies prospective injection sites based on favorable subsurface storage conditions and
better informs permitting strategy, surface facility planning, and mitigates the risk of CO2 leakage or
permit denial.
Demonstrating geological storage permanence is an iterative process of data gathering, integration, and
dynamic flow simulation. In order to scale CCS technologies and ensure efficiency, a comprehensive
development program is needed that includes everything from pre-injection permitting, subsurface
modelling, and infrastructure build to advanced site characterization and plume monitoring.
Schlumberger has over a decade of multi-discipline carbon sequestration experience and has developed
geologic criteria and monitoring programs using Petrel* and Eclipse* to ensure successful permanence
of CO2 storage at commercial scale for the purpose of facilitating low carbon energy sources and
reducing global carbon emissions.
The study area for site identification and ranking is in the Los Angeles Basin, California (Figure 1). The
purpose of this study is to demonstrate site identification and ranking workflows and subsequent
dynamic simulation. This area is considered infeasible for geologic storage due to the environmental,
societal, and governance concerns associated with the large residential population density and the
proximity of the San Andreas fault system. In commercial evaluations local regulations concerning
environmentally sensitive areas and highly populated residential areas would dictate proposed location
criteria but have not been considered here for demonstrational purposes.
Background Geology
The Los Angeles Basin is the largest of the California Peninsular Range basins with an area of 1,500
square miles and a sedimentary thickness of roughly 27,000 ft. The basin formed in three major phases:
an extensional phase from the mid-Miocene through the early Pliocene associated with the opening of
the Gulf of California, a subsidence and deposition phase from the Late Miocene through the early
Pleistocene, and a post-Pleistocene compressional phase of extensive faulting and folding.
The Los Angeles Basin lies in a tectonically active area. Three major fault zones- the Palos Verde, the
Newport-Inglewood, and the Whitier- divide the basin into blocks. The middle axial trough block
between the Newport-Inglewood and Whitier zones contains the area of interest for this study. The
principal horizontal stress direction of these large fault systems is N-NW; therefore, borehole breakouts
tend to favour approximately E-W (Chavez, 2015). The basin depocenter in the Central Block is less
faulted and experiences less seismicity. Four major sedimentary formations are defined in the basin: the
Topanga, Puente, Repetto, and Pico from deepest to shallowest of which the middle two are primary
hydrocarbon reservoirs. The Puente Formation consists of about 8,000 ft of bathyal silt and sandstones
and is characterized by three distinct zones of varying grain size. The Repetto Formation is deepest in
the central block, reaching thicknesses of over 10,000 ft, and consists of southward prograding lower
submarine fan deposits (California Geological Survey, 2006).
Methodology
In the first stages of a CCS project, the operator must understand if there are suitable subsurface storage
formations that will accept and contain the injected CO2. Geologic storage systems must demonstrate
that saline (>10,000 ppm) formations exist at depths below the minimum super critical CO2 depth (-
2,500 ft) and exhibit favorable injectivity properties (porosity, permeability, salinity, temperature and
pressure) (EPA, 2018). More importantly, regional low-permeability seals must exist and demonstrate
that injected CO2 will be permanently isolated in the injection reservoir. In addition to injectivity and
seal characterization, it must be proven that no potential pathways exist from the CO2 storage reservoir
to the surface including leaky faults and improperly abandoned wells. Such subsurface features can act
as conduits for upwards CO2 movement, resulting in contamination of Underground Sources of
Drinking Water (USDWs). Regional dip affects plume migration and must be considered when
selecting locations.
To identify prospective storage site locations subsurface data was integrated into Petrel* subsurface
modelling software. Within the study area there are 3066 legacy wells (IHS, 2020). Interpreted well
tops and published maps provided input for the structural model (CalGEMS, 2020) (Wright, 1991)
(California Geological Survey, 2006). Raster log images were used to interpret 21 lithofacies logs for
sand, sand-shale, and shale layers across the study area (IHS, 2020). Base of freshwater was mapped
and is variable across the study area ranging from 500 – 3,500 ft (USGS, 2018). Lithofacies
interpretation provided the input for full field modelling using Sequential Indicator Simulation (SIS)
facies modelling algorithm in Petrel*. Variogram parameters were selected from estimated sediment
transport direction and calculated facies variance. Due to the lack of digital well data, constant porosity
and permeability values were estimated from field data (DOGGR, 1992). The model was used in
conjunction with aforementioned feasibility criteria to identify five prospective injection locations
labelled A-E (Figure 1).
After identifying proposed locations, a ranking system was applied per location to understand feasibility
of the geologic storage system. Evaluation criteria for this study are shown in Figure 2.a. and include
fault leakage and reactivation, distance to subsurface operations, and reservoir storage potential.
Reservoir storage potential is calculated based on simulated sand thickness with constant porosity using
the Department of Energy’s (DOE) CO2 storage for saline reservoirs (DOE, 2015). CO2 density was
calculated using reservoir temperature and pressure (DOGGR, 1992) (Span & Wagner, 1996). Each
area is ranked relative to each other on an unweighted scale of 1-5, 1 being most favorable and 5 being least favorable. The result of this preliminary analysis is a quantitative understanding of subsurface
risks by identifying locations that have the lowest score, i.e., are most favorable for geologic storage.
A dynamic model was constructed over the most favorable injection location to simulate saline storage
using Eclipse* E300 compositional reservoir simulator. A subset of the geomodel covering an 8.1 mile
x 9.1 mile area around the most favorable injection location was used as input for the dynamic model.
Property upscaling was applied to the new grid with a cell size of 330 ft x 330 ft to reduce the number
of cells and improve computational efficiency. The reservoir was assumed to be 100% brine saturated
with an initial formation salinity of 15,000 ppm, based on the data from nearby oil and gas fields
(DOGGR, 1992). For dynamic modelling, the injected fluid is assumed to be pure CO2. Infinite-acting
conditions were assumed at the lateral boundaries to serve as pressure sinks/sources during and after
the injection. Continuous injection with a rate of 1 million tonnes/year was applied for 20 years. A 50-
year post-injection period was added to understand plume stabilization and inform monitoring
strategies.
Conclusions
The Repetto formation was delineated as the best reservoir candidate due to both sand thickness and
overlying seal presence. Silt and mudstone layers in the overlying Pico Formation provide regional
seals up to around 330 ft thick. Site evaluation criteria and ranking show that proposed injection site B
is the most feasible for long term geologic storage (Figure 2.a.). Ranking shows proposed injection
sites D, E, and C are the least favourable targets due to their proximity to active and legacy wells.
Based on historical earthquake data, proposed injection sites D and E are more susceptible to future
earthquake events. Dynamic modelling was conducted over proposed injection site B. Figure 2.b. and
Figure 2.c. show results of dynamic modelling and estimated plume geometry after 20 years injection
and 50 years post-injection. Although this site would never be recommended for commercial storage,
the same prospect assessment, subsurface characterization, and dynamic modelling workflow
showcased here can be implemented for the full spectrum of carbon storage cases using
Schlumberger’s Petrel* and Eclipse* software.
References
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