Assessment of Dynamic Flow, Pressure and Geomechanical Behaviour of a CO2 Storage Complex

Ernest Ncha Mbia

Research output: Book/ReportPh.D. thesis

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Abstract

The increasing global temperature is of much concern to the present and future society and is drawing much attention to climate change causes and consequently, significant efforts are being made to mitigate global emissions of greenhouse gases from the atmosphere as one of the main causes. Carbon dioxide (CO2) is the primary greenhouse gas emitted through human activities. Over 7,500 large CO2 emission sources (above 0.1 million tons CO2 year-1) have been identified (IPCC, 2005). These sources are distributed geographically around the world but four clusters of emissions can be observed: in North America (the Midwest and the eastern freeboard of the USA), North West Europe, South East Asia (eastern coast) and Southern Asia (the Indian sub-continent).One of the ways in which global emission of CO2 can be reduce is by capturing large volumes of CO2 from point sources (carbon emitters such as coal-fired power plants) and injecting it into deep formations (e.g., saline aquifers, oil and gas reservoirs, and coalbeds) for storage. This process has drawn increasing consideration as a promising mitigation method that is economically possible. Deep saline aquifers offer the largest storage potential of all the geological CO2 storage options and are widely distributed throughout the globe in all sedimentary basins. CO2 storage cannot have a significant impact on reducing atmospheric levels of greenhouse gases if the amounts of CO2 injected and sequestered underground is not extremely large. However, there is concern that storing extremely large amounts of supercritical CO2 in deep formations will introduce additional fluids that may cause pressure changes and displacement of native brines thereby affecting subsurface volumes that can be significantly larger than the CO2 plume itself. If this happens it will be of great environmental concern especially to the ground water and other subsurface resources implying that quantifying pressure changes in CO2 sites is very important for monitoring purposes in order to prevent this phenomenon.
Large scale CO2 storage has previously been considered for the Vedsted structure located in the Northern part of Jylland in Denmark. In the Vedsted site the primary caprock is the 530 m thick Fjerritslev Formation sealing the Gassum Formation. The Fjerritslev Formation extends from the Norwegian-Danish Basin to the Northeast and North Sea Central Graben to the Southwest. The magnitude of pressure buildup and transmission from the reservoir into the surrounding formations will depend on the properties (compressibility and permeability) and thickness of the sealing rock and presence of faults. Pressure buildup in the Gassum reservoir and transmission to the shallower Chalk Group where the brine-fresh water interface resides need to be investigated and quantified through simulation studies as part of site qualification, as overpressure can push brine into the fresh water zone and thereby affecting aquifer performance.
In order to estimate the sealing potential and rock properties, samples from the deep wells, Vedsted-1, in Jylland and Stenlille-2 and -5 on Sjælland were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analysis based on X-ray diffractometry (XRD) of shale cuttings samples obtained from the three different locations show a clear trend in composition from the Northeast presently onshore of the Norwegian-Danish Basin where we encounter a more silty shale with up to 50% quartz content to less silty shale of about 30% quartz content in the Southwest, offshore section of the Central Graben. Illite and kaolinite dominate the clay fraction.
The equivalent pore radius that links permeability and porosity of a porous medium was calculated from specific surface and porosity data measured in the laboratory. In this study we demonstrate that elastic moduli as calculated from bulk density and velocity of elastic waves relate to equivalent pore radius of the studied shales. This relationship establishes the possibility of calculating equivalent pore radius from logging data. We found exponential relationships between equivalent pore radius and elastic moduli, and these empirical relationships were used to calculated equivalent pore radius for the Cenozoic, Cretaceous and Jurassic shale sections in Skjold Flank-1 well from elastic moduli, calculated from sonic velocity and density logs. The calculated equivalent pore radius logs vary from 27 nm at 500 m to 13 nm at 2000 m within Cenozoic shale and from 12 nm to about 6 nm in the deeper Cretaceous and Jurassic shale intervals.
Porosity of shale was measured from three independent methods including helium porosimetrymercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) and the results on same material show that MICP porosity is 6% to 10% points lower than HPMI or NMR porosity. Compressibility from uniaxial loading and velocity of elastic waves were measured simultaneously on saturated samples under drained condition at room temperature. Uniaxial loading causes both elastic and plastic deformation at low stress, but unloading at stress corresponding to in situ stress gives stiffer material with high elastic moduli close to values calculated from mass density and velocity of elastic waves. This result indicates that shale is significantly stiffer in situ than normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli and from combined MICP and NMR data. The predicted permeability from BET specific surface using Kozeny’s formulation for these shales being rich in silt and kaolinite fall in the same order of magnitude as measured permeability from constant rate of strain (CRS) experiments, but is two to three orders of magnitude higher than the predicted permeability from the Yang and Aplin model, which is based on clay fraction and average pore radius. We also found that taking Biot’s coefficient into account when interpreting CRS data has a significant and systematic influence on resulting permeability of deeply buried shale.
The second part of this project is focused on assessing two scenarios including sensitivity of caprock permeability and compressibility on pressure development and transmission to the shallower Chalk Group where the brine-fresh water interface resides due to large scale CO2 storage in Vedsted structure when faults are ignored and when faults are considered. The measured compressibility for the Fjerritslev Formation is 0.5 x 10-5 bar−1, which is an order of magnitude lower than the standard compressibility (4.5 × 10−5 bar−1) normally used for reservoir simulation studies. The consequences of this lower compressibility are investigated in a simulation case study by injecting 60 million tons (Mt) of CO2 at a rate of 1.5 Mt/year into the Gassum Formation for 40 years. The results indicate that overpressure difference of about 5 bar is created in the reservoir and the caprock between the case with measured and the standard compressibility case. Overestimating caprock compressibility can therefore underestimate overpressure within the storage and sealing formations and this can have significant implication in the presence of highly permeable fractures and faults. The sensitivity of pressure development for the caprock permeability has been studied by varying from one to three orders of magnitude higher and one to two orders of magnitude lower than the measured permeability value of 0.1 μD. The results show that with permeability above 1.0 μD which is higher than the measured value, overpressure can be transmitted through the 530 m thick Fjerritslev Formation caprock and further up into the overburden layers.
Seismic profiling of the structure shows the presence of Northwest-Southeast trending faults of which some originate in the upper layer of the Gassum reservoir and some reach the base Chalk Group layer. Two faults in the upper Gassum reservoir have been interpreted to be connected to the base Chalk Group. In order to evaluate potential risks associated with vertical pressure transmission via the faults through the caprock, a number of simulation cases have been run with various fault permeabilities spanning orders of magnitude to represent both the worst and best case scenarios. Fault rock permeability data were obtained from a literature study and range from 1000 mD (common in crystalline rock environment) for the worst case scenario down to 1.0 μD (common in sedimentary rock environment) for the best case scenario. The results show that after injecting 60 million tons (Mt) of CO2 at a rate of 1.5 Mt/year for 40 years, overpressure is developed in the reservoir and about 5 bar is transmitted to the base Chalk Group for the 1000 mD fault permeability (worst) case, while for the 1.0 μD (best) case the pressure buildup was confined within the primary caprock. The results also show that, approximately 0.3 to 5.0 bar overpressure can be transmitted to the base Chalk Group when the fault permeability is above 1.0 mD. The evaluation of Vedsted site from this work has been based on pressure development and CO2 plume distribution 40 years after injecting 60 Mt of supercritical CO2 into the Gassum Formation. The results based on both best and worst case scenarios show no potential short term threat to CO2 storage in Vedsted site. This work underscores the importance of obtaining site specific data for simulation study of potential CO2 storage sites. Laboratory data generated and methodology employed during this study can be useful for other simulation work and scientific investigations.
Original languageEnglish
PublisherTechnical University of Denmark, Department of Civil Engineering
Number of pages212
Publication statusPublished - 2014

Bibliographical note

DTU Civil Engineering Report R-310 (UK)

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