• Geosystem Engineering
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• v.21 no.6
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• pp.344-351
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• 2018

It is reported that the flooding rate in low permeability sandstones is low and the oil recovery is hard to increase after water breakthrough. Understanding characteristics of waterflood is hence important for the recovery improvement. In this work, flooding tests on low permeability sandstones were conducted. The corresponding flooding characteristics were investigated by means of CT scanning and Nuclear Magnetic Resonance. Effects of irreducible water and different rates were also discussed in detail. Experimental results reveal a piston-like displacement at a low rate in low permeability samples. The saturation profile is steep and almost vertical to the forward direction. The results at a low rate confirm that once water broke through, increasing the flooding rate or flooding time can hardly reduce the remaining oil inside the sample. It is probably due to the high pore-throat ratio proven by rate-controlled mercury. Results also confirm that the presence of initial water enhanced sweep efficiency substantially. On one hand, because water had previously occupied the small pores, the subsequent oil can only invade relatively large pores and became more movable. On the other hand, stable collars can not form due to the steep front, which may suppress the snap-off.

• The Journal of Engineering Geology
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• v.29 no.4
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• pp.367-381
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• 2019

We investigate pore pressure conditions and reservoir compaction associated with oil and gas production using 3 different permeability models, which are all based on one-dimensional radial flow diffusion model, but differ in considering permeability evolution during production. Model 1 assumes the most simplistic constant and invariable permeability regardless of production; Model 2 considers permeability reduction associated with reservoir compaction only due to pore pressure drawdown during production; Model 3 also considers permeability reduction but due to the effects of both pore pressure drawdown and coupled pore pressure-stress process. We first derive a unified stress-permeability relation that can be used for various sandstones. We then apply this equation to calculate pore pressure and permeability changes in the reservoir due to fluid extraction using the three permeability models. All the three models yield pore pressure profiles in the form of pressure funnel with different amounts of drawdown. Model 1, assuming constant permeability, obviously predicts the least amount of drawdown with pore pressure condition highest among the three models investigated. Model 2 estimates the largest amount of drawdown and lowest pore pressure condition. Model 3 shows slightly higher pore pressure condition than Model 2 because stress-pore pressure coupling process reduces the effective stress increase due to pore pressure depletion. We compare field data of production rate with the results of the three models. While models 1 and 2 respectively overestimates and underestimates the production rate, Model 3 estimates the field data fairly well. Our result affirms that coupling process between stress and pore pressure occurs during production, and that it is important to incorporate the coupling process in the permeability modeling, especially for tight reservoir having low permeability.

• Tunnel and Underground Space
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• v.23 no.3
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• pp.169-179
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• 2013

Well testing in unconventional reservoirs, such as tight or shale gas formations, presents considerable challenges. It is difficult to estimate the reservoir properties in ultra-low permeability formation because of poor inflow prior to stimulation and excessive test duration. Moreover, radial flow may not develop in hydraulically fractured horizontal wells. For these reasons, the cost of test is high and the accuracy is relatively low. Accordingly, industry is turning to an alternate testing method, diagnostic fracture injection test (DFIT), which is conducted prior to the main hydraulic fracture treatments. Nowadays, DFIT are regarded as the most practical way to obtain good estimates of reservoir properties in unconventional reservoirs. Various methods may be used for interpreting DFIT data. This paper gives an explanation of those methods in detail and examines three actual field data. These show how various analysis methods can be applied to consistently interpret fracture closure pressure and time, as well as before and after closure flow regimes and reservoir properties from field data.

• Geomechanics and Engineering
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• v.20 no.6
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• pp.537-546
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• 2020

Oil and natural gas reserves have been recognised abundantly in clayey rich rock formations in deep costal reservoirs. It is necessary to understand the sedimentary history of those reservoir rocks to well explore these natural resources. This work designs a group of laboratory experiments to mimic the physical process of the sedimentary clay-rich rock formation. It presents characterisation results of the physical properties of the artificial clayey rocks synthesized from illite clay, quartz sand and brine water by high-pressure consolidation tests. Special focus is given on the effects of illite clay content and high-stress consolidation on the physical properties. Multi-step loaded consolidation experiments were carried out with stress up to 35 MPa on mixtures constituting of the illite clay, quartz sand and brine water with five initial illite clay contents (w=85%, 70%, 55%, 40% and 25%). Compressibility and void ratio were characterised throughout the physical compaction process of the mixtures constituting of five illite clay contents and their water permeability was measured as well. Results show that the applied stress induces a great reduction of clayey rock void ratio. Illite clay contents has a significant influence on the compressibility, void ratio and the permeability of the physically synthesized clayey rocks. There is a critical illite clay content w=70% that induces the minimum void ratio in the physically synthesised clayey rocks. The SEM study indicates, in the high-pressure synthesised clayey rocks with high illite clay contents, the illite clay minerals are located in layers and serve as the material matrix, and the quartz minerals fill in the inter-mineral pores or are embedded in the illite clay matrix. The arrangements of the minerals in microscale originate the structural anisotropy of the high-pressure synthesised clayey rock. The test findings can give an intuitive physical understanding of the deep-buried clayey rock basins in energy reservoirs.

• Journal of the Korean GEO-environmental Society
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• v.25 no.6
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• pp.5-12
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• 2024

Currently, a grouting method that minimizes damage to the reservoir embankment by injecting solidification agent at low pressure is commonly used to ensure waterproofing and safety of the embankment, but the use of solidification agents can cause issues, such as a decrease in durability and a lack of clear method for determining the mixing ratio. In this study, when the base ground and solidification agent were stirred and mixed at various weight mixing ratios, the permeability coefficient and strength of the mixture were confirmed through laboratory tests, and the optimal mixing ratio was suggested through analysis of the test results. The specimen for the laboratory test was produced considering the mixing ratio of the solidification agent. The specimen for the permeability coefficient test was tested by producing one each of cohesionless and cohesive soil for a mixing amount of 1.5 kN/m³ of solidification agent, and the permeability test results confirmed that the water barrier performance was secured below the permeability coefficient value required by various design criteria. A total of 24 specimens for the strength test were produced, 3 for each of 5 mixing amounts for cohesive soil and 3 mixing amounts for cohesionless soil. The strength test results showed that the uniaxial compressive strength tends to increase linearly with increasing curing time for both cohesionless soil and cohesive soil when the mixing amount is less than 2.0 kN/m³. Therefore, the optimal mixing ratio applied to the site is determined to be mixing amount of 1.5 kN/m³ and 2.0 kN/m³. Finally, numerical analysis reflecting test results was conducted on design case for improvement projects for aging reservoirs embankment to verify the water barrier performance and safety improvement effects.

• Proceedings of the Korean Geotechical Society Conference
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• 2010.09a
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• pp.790-799
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• 2010

The Upper Devonian Grossmont Formation in Alberta, Canada reserves an estimated 50 billion cubic meters of bitumen and possess about 1/6 of the total bitumen resources in northern Alberta. However, unlike the overlying Athabasca oil sands, non conventional bitumen resources has not been developed as yet. The carbonate rocks of Grosmont Formation have been subject to various stages of diagenesis, including dolomatization and karstification with a strong effect on the distribution of porosity and permeability, which resulted in highly heterogeneous reservoirs. An extensive fracture logging and mapping was performed on total of six boreholes located in the study area to explore the characteristics of fracture geometry system and the subsurface structures of carbonates reservoir that holds bitumen. Fractal dimension was used as a measure of the statistical homogeneity of the fractured rock masses. The applicability of random Cantor dust, Dc, as a fractal parameter was examined systematically. The statistical homogeneity of fractured carbonates rock masses was investigated in the study area. The structural domains of the rock masses were delineated depthwise according to estimated Dc. The major fracture orientation was dominated by horizontal beddings having dip of $0-20^{\circ}$. Also, fractures having high dip angles existed with relatively low frequency. Three dimensional fracture network modeling for each structural domain has been performed based on fracture orientation and intensity, and some representative conceptual models for carbonates reservoir in the study area has been proposed. The developed subsurface conceptual models will be used to capture the geomechanical characteristics of the carbonates reservoir.

• Geomechanics and Engineering
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• v.17 no.6
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• pp.535-541
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• 2019

Combining the radial well drilling and hydraulic fracturing technique, the production capacity of the reservoirs with low-permeability can be improved effectively. Due to the existence of radial holes, the stress around the well is redistributed, and the initiation and propagation of hydraulic fractures are different with those in traditional hydraulic fracturing. Therefore, it is necessary to study the influences of radial horizontal wells on hydraulic fracturing. The laboratory experiment was conducted to simulate the hydraulic fracturing on the physical model with radial holes. The experimental results showed that, compared with the borehole without radial holes, the sample with radial hole in the direction of maximum horizontal stress was fractured with significantly lower pressure. As the angle between direction of the horizontal hole and the maximum horizontal stress increased, the breakdown pressure grew. While when the radial hole was drilled towards the direction of the minimum horizontal stress, the breakdown pressure increased to that needed in the borehole without radial holes. When the angle between the radial hole and the maximum horizontal stress increase, the pressure required to propagate the fractures grew apparently, and the fracture become complex. Meanwhile, the deeper the radial hole drilled, the less the pressure was needed for fracturing.

• The Korean Journal of Petroleum Geology
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• v.4 no.1_2 s.5
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• pp.27-39
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• 1996

In the Cretaceous, the Gulf Coast Basin evolved as a marginal sag basin. Thick clastic and carbonate sequences cover the disturbed and diapirically deformed salt layer. In the Cretaceous the salinities of the Gulf Coast Basin probably matched the Holocene Persian Gulf, as is evidenced by the widespread development of supratidal anhydrite. The major Lower Cretaceous reservoir formations are the Cotton Valley, Hosston, Travis Peak siliciclastics, and Sligo, Trinity (Pine Island, Pearsall, Glen Rose), Edwards, Georgetown/Buda carbonates. Source rocks are down-dip offshore marine shales and marls, and seals are either up-dip shales, dense limestones, or evaporites. During this period, the entire Gulf Basin was a shallow sea which to the end of Cretaceous had been rimmed to the southwest by shallow marine carbonates while fine-grained terrigengus clastics were deposited on the northern and western margins of the basin. The main Upper Cretaceous reservoir groups of the Gulf Coast, which were deposited in the period of a major sea level .rise with the resulting deep water conditions, are Woodbinefruscaloosa sands, Austin chalk and carbonates, Taylor and Navarro sandstones. Source rocks are down-dip offshore shales and seals are up-dip shales. Major trap types of the Lower and Upper Cretaceous include salt-related anticlines from low relief pillows to complex salt diapirs. Growth fault structures with rollover anticlines on downthrown fault blocks are significant Gulf Coast traps. Permeability barriers, up-dip pinch-out sand bodies, and unconformity truncations also play a key role in oil exploration from the Cretaceous Gulf Coast reservoirs. The sedimentary sequences of the major Cretaceous reseuoir rocks are a good match to the regressional phases on the global sea level cuwe, suggesting that the Cretaceous Gulf Coast sedimentary stratigraphy relatively well reflects a response to eustatic sea level change throughout its history. Thus, of the three main factors controlling sedimentation (tectonic subsidence, sediment input, and eustatic sea level change) in the Gulf Coast Basin, sea-level ranks first in the period.