Pulses of carbon dioxide emissions from intracrustal faults following climatic warming. Nature Geosci 5 , — Roberts, J. Assessing the health risks of natural CO 2 seeps in Italy. PNAS , — International Journal of Greenhouse Gas Control 23 , 1—11 Miocic, J.
Controls on CO 2 storage security in natural reservoirs and implications for CO 2 storage site selection. International Journal of Greenhouse Gas Control 51 , — Gilfillan, S. Solubility trapping in formation water as dominant CO 2 sink in natural gas fields. Nature , — Allis, R. In American Association Petroleum Geologists meeting Sathaye, K. Constraints on the magnitude and rate of CO 2 dissolution at Bravo Dome natural gas field.
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Stress-dependent permeability of fractured rock masses: a numerical study. Enting, I. A perturbation analysis of the climate benefit from geosequestration of carbon dioxide.
Stone, E. The impact of carbon capture and storage on climate. Energy Environ. Authors Close. Assign yourself or invite other person as author. It allow to create list of users contirbution.
Assignment does not change access privileges to resource content. Wrong email address. You're going to remove this assignment. Are you sure? Yes No. Additional information Publication languages: English. Data set: Elsevier. Publisher Elsevier Science. Carbonates and sulfates commonly occur as primary diagenetic pore cements and secondary fluid-mobilized veins within fault zones. Stable isotope analyses of calcite, formation fluid, and fault zone fluids can help elucidate the carbon sources and the extent of fluid-rock interaction within a particular reservoir.
The Colorado Plateau contains a number of large carbon dioxide reservoirs some of which leak and some of which do not. Several normal faults within the Paradox Basin SE Utah dissect the Green River anticline giving rise to a series of footwall reservoirs with fault-dependent columns.
Therefore, conclusively, the three-dimensional sector model is observed to relay a maximum cumulative production of These dates were then used as the shut-in dates for each respective producer. The injector shut-in dates were correlated to the time taken to inject a specific volume of carbon dioxide into the storage formation. This 1 pore volume maximum capacity of the storage formation was regarded as a conservative limit.
Such a conservative approach is taken so as to ensure that injection activities do not propagate hydraulic fractures within our reservoir and thus stimulate leakage. The resulting calculation can be observed below.
As a result, all injectors were shut-in after 53 years of carbon dioxide injection. The producer located at the topmost layer was then opened to production, and the model was allowed to run for 88 years to observe the action of various trapping mechanisms at work. The resultant calculation can be observed in the following few lines;.
Following this operation outlined above, the simulation run was implemented which saw the producer at the topmost sand layer of the sector model not registering a gas rate, and thus it was concluded that leakage of the injected carbon dioxide did not occur.
However, it is expected that some of the injected carbon dioxide was produced during the EOR process. In light of such, a mass balance approach was undertaken to quantify the volume of injected carbon dioxide, which remained within the reservoir. From Fig. As a result, the volume of carbon dioxide still present within the formation was equated as the difference between these two values.
The resultant calculation can be observed in Table 6 , which depicts the total volume of carbon dioxide still present within the storage formation as Illustration of total volume of carbon dioxide injected, and total volume of carbon dioxide produced during combined CO 2 EOR and sequestration. This As previously mentioned, these trapping mechanisms include dissolution trapping, mineral precipitation, structural trapping, and trapping by hysteresis.
The corresponding amounts in pounds, for each type of trapping, can be observed in Fig. This graphical data is also summarized and presented in a tabular manner, as depicted in Table 7.
The general trend inferred from comparing each type of trapping on one singular plot shows that the major quantity of trapped carbon dioxide is initially facilitated by trapping in the supercritical phase.
This can be attributed to the action of primary trapping mechanisms, such as structural trapping which acts to hold the supercritical carbon dioxide in place.
In addition, significantly trapped volumes are also facilitated by trapping present in the form of aqueous ions and carbon dioxide dissolved in aqueous state. Illustration of the mass of carbon dioxide stored within the formation for each trapping mechanism. The remaining volume of carbon dioxide is trapped by the action of secondary mechanisms, which typically comes into operation over prolonged periods, usually in the magnitude of thousands of years.
Since the study was only conducted over an year period, the action of secondary trapping mechanisms are relatively insignificant and thus accounts for such small amounts of trapping associated with mineralization and dissolution. For the Geomechanical study of fault reactivation, a simple two-dimensional block model was constructed to represent a thin two-dimensional homogenous segment of the larger GEM field model. As such, the block model was constructed using the same reservoir, rock, and fluid properties as the field model.
The GEM suite was also used as the simulator type, and as a result, the model was also populated with the same Winprop fluid model created previously. The model laterally spans feet in length by 10 feet in width. Formation thickness is The topmost sand unit is capped with an additional 10 feet of impermeable shale and 2. These two additional layers are not included in the GEM three-dimensional field model and are only incorporated in the 2D segment for the purpose of quantifying leakage associated with fault reactivation.
The fault vertically spans the entire thickness of the reservoir and therefore consists of nine grid blocks adjacent to the nine layers of the reservoir. Figure 12 depicts the faulted three-dimensional view of this simple block model. Initially, the producer is placed at the topmost layer of the fault to quantify leakage associated with fault reactivation.
The injector, however, is approximately feet away from the fault, which is represented by the vertical arrangements of blue grid blocks. The fault is modelled as initially sealing and hence, comprise of a sealing potential which is broadly quantified by the capillary entry pressure and permeability. These are generally regarded to have the most significant impact on leakage, and thus, the dynamic sealing capacity of the fault was modelled and resolved numerically by coupling rock deformation, prompted by reservoir pressurization and modifying fluid flow properties.
This type of modelling is preferred when the simulation of fluid transport is the main factor being investigated for the fault. Three-dimensional view of the 2D homogeneous layered model for geomechanical study of fault reactivation. However, as the modelling of fault reactivation, geomechanics, and the respective changes in permeability form the underlying basis of the study, the modelling approach undertaken for this 2D reservoir model applies a geomechanical based approach to simulate variations of openness within the fault.
Such variations are based on increases in hydraulic fracture permeability, influenced by pressurization via carbon dioxide injection. Refer to the theory section for the concepts at work for each of the aforementioned submodels used. Initially, gas was injected in the bottommost sand unit and then allowed to pressurize the layer to investigate the occurrence of fault reactivation via the action of the Barton Bandis submodel.
Importantly, however, the application of the Barton—Bandis submodel saw the fault reactivating on a grid block basis, as depicted in Fig. Within the following sections, the depicted fault block numbers presented in Fig. Illustration of fault reactivation and fault-block numbering for referencing during discussions on reactivation results. Despite this, the operation and application of the Barton Bandis submodel required a value be set for fracture opening stress. However, by manually setting this value, we are in essence, controlling fault reactivation and the pressure at which it occurs.
As a result, to accurately capture the characteristics of fault reactivation, a sensitivity analysis on fracture opening stress was undertaken. Although a duration of fifty years may seem impractical from a recovery standpoint, the study on reactivation is also in regard to sequestration, which typically operates for lengthy periods. The results of the simulation runs are presented and explained below. Figure 14 depicts a plot of vertical permeability against time and was used as the analysis to observe the effect of varying fracture opening stresses on fault reactivation time.
The basis of the investigation, however, centers on simulating reactivation or the lack thereof, under constant injection at varying fracture opening stresses. These variations of fracture opening stress were observed to have a significant effect on the time taken for fault reactivation. This is confirmed as the fault is observed to undergo reactivation at the base fault block 1 , under a fault opening stress of 25 psi, however, does not reactivate at a fault opening stress of 10 psi.
As a result, it can be deduced that under these geomechanical and injection constraints, all faults with fracture opening stresses higher than 25 psi, are expected to undergo fault reactivation. Moreover, the general trend inferred from Fig. Therefore, an inverse relationship between the two variables is established, such that, for example, the time taken for reactivation at fracture opening stress equals psi, is approximately half the time taken for reactivation at fracture opening stress equals psi.
This trend can be attributed to the mechanism of the Barton—Bandis submodel and the relationship between normal effective stress and pore pressure within a specific grid block. That is;.
Time taken for the onset of fault reactivation at the base of the fault for varying fracture opening stresses. From the above relationship, it can be inferred that as pore pressure increases, normal effective stress decreases. Since injection was simulated at a constant rate, this infers a constant increase in pore pressure for all simulation runs. Such a constant increase in pore pressure thus infers a constant decrease in normal effective stress.
Complimentary to this, recall that such a decrease in normal effective stress forms the basis of operation of the Barton—Bandis submodel. That is, an increase in fracture permeability which is indicative of fault reactivation is prompted when the normal effective stress decreases so much so that it equates or becomes less than the fracture opening stress.
Therefore, as we are increasing fault opening stress, we are essentially decreasing the difference between normal effective stress and fault opening stress. This reduction in the difference between the two stresses thus infers a smaller value of pore pressure required to reduce the normal effective stress to equate or become less than the fracture opening stress, that is, to prompt reactivation.
This lesser value of pore pressure requires less injection for reactivation and thus translates to a faster reactivation time. Likewise, the opposite occurs when fracture opening stress is decreased, and therefore accounts for the trend observed within Fig.
In addition to investigating reactivation at the base of the fault, an analysis was undertaken at the topmost fault block, that is, at fault block nine. The primary purpose of this study was to investigate the occurrence, or lack thereof, of fracture propagation along the entire thickness of the reservoir. This also forms an integral part of a subsequent investigation into the leakage associated with reactivation.
As a result, the occurrence of reactivation was observed by a similar plot of vertical permeability against time. The result of this study can be observed in Fig. From the respective plot, only two instances of fracture propagation were observed to have affected the topmost layer of the formation fault block 9.
These were seen to occur at psi and psi, respectively, that is, at the largest values of fracture opening stress. As a result, it can be deduced that at values of fracture opening stress less than psi, the fault undergoes partial reactivation and leakage does not reach the topmost layer of the reservoir. Time taken for onset of fault reactivation at the top of the fault for varying fracture opening stresses.
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