Multistage hydraulic fracturing techniques, combined with horizontal drilling, have enabled commercial production from the vast reserves of unconventional tight formations. During hydraulic fracturing, fracturing fluid and proppants are pumped into the reservoir matrix to create the hydraulic fractures. Understanding the propagation mechanism of hydraulic fractures is essential to estimate their properties, such as half-length. In addition, natural fractures are often present in tight formations, which might be activated during the fracturing process and contribute to the post-stimulation well production rates. In this study, reservoir simulation is integrated with rock geomechanics to predict the well post-stimulation productivities. Firstly, a reservoir geological model is built based on the field data collected from the Montney formation in the Western Canadian Sedimentary Basin. The hydraulic fracturing process is then simulated through an integrated approach of fracturing fluid injection, rock geomechanics, and tensile failure criteria. In such a process, the reservoir pore pressure increases with a continuous injection of the fracturing fluid and proppants, decreasing the effective stress exerted on the rock matrix accordingly as the overburden pressure remains constant. Once the effective stress drops to a threshold value, tensile failure of the reservoir rock occurs, creating hydraulic fractures in the formation. The early production history of the stimulated well is history-matched to validate the predicted fracture geometries (e.g., half-length) generated from the fracturing simulation process. The effects of the natural fracture properties and well bottom-hole pressures on well productivity are also studied. It has been found that nearly 40% of hydraulic fractures propagate in the beginning stage (the pad step) of the fracturing schedule. In addition, well post-stimulation productivity will increase significantly if the natural fractures are propped or partially propped by the proppants. This paper provides insights on fracture propagation and can be a reference for fracturing treatments in unconventional tight reservoirs.

In the description of multiphase flow in porous media, dynamic capillarity is typically ignored. While some studies suggest that dynamic capillarity can be ignored in high permeability rock, it cannot be overlooked in low permeability rock. In this work, dynamic capillarity, in various permeability formations, was investigated through specially designed experiments and the impact on field production is simulated. First, capillarity characters (capillary pressure-saturation relationships and relative permeability curves) were obtained during the static and dynamic waterflooding process conducted in different permeability core samples under in-situ reservoir conditions. The dynamic coefficients were calculated locally and compared. Then experimental results were subjected to sensitivity analyses, through numerical simulation studies using CMG (IMEX), to determine the dynamic capillary effects on different permeability cases. The results show that (a) a low permeability formation constitutes a much larger dynamic coefficient, thus resulting in a significant difference between dynamic and static capillary pressures; (b) the lower the rock permeability, the larger the difference between static and dynamic relative permeability curves; (c) the dynamic capillary pressure in low permeability formations, compared with static capillary pressure, can be notably large, causing irregular differences in phase behavior and pressure distribution. This work demonstrates the importance of considering dynamic capillarity in low permeability reservoirs. (C) 2016 Elsevier Ltd. All rights reserved.

Summary The Fjerritslev Formation in the Norwegian-Danish Basin forms the main seal to Upper Triassic-Lower Jurassic sandstone reservoirs. In order to estimate rock properties Jurassic shale samples from deep onshore wells in Danish basin were studied. Mineralogical analysis based on X-ray diffractometry (XRD) of shale samples show about 50% silt and high content of kaolinite in the clay fraction when compared with offshore samples from the Central Graben. Porosity measurements from helium porosimetry-mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) show that, the MICP porosity is 9–10% points lower than HPMI and NMR porosity. Compressibility result shows that deep shale is stiffer in situ than normally assumed in geotechnical modelling and that static compressibility corresponds with dynamic one only at the begining of unloading stress strain data. We found that Kozeny’s modelled permeability fall in the same order of magnitude with measured permeability for shale rich in kaolinite but overestimates permeability by two to three orders of magnitudes for shale with high content of smectite. The empirical Yang and Aplin model gives good permeability estimate comparable to the measured one for shale rich in smectite. This is probably because Yang and Aplin model was calibrated in London clay which is rich in smectite.

Assessing the pressure buildup in CO2 storage sites and especially the vertical propagation is vital for evaluation of site behavior and security. Vedsted structure in the Northern part of Jylland in Denmark consists of 290 m thick Gassum Formation at 2100 m depth forming the primary reservoir and is sealed by the 530 m thick Fjerritslev Formation which is mainly shale lithology with very low permeability. Overlying the caprock is a number of formations forming secondary reservoirs and seals including a 420 m thick Chalk Group which is overlain by 20-50 m Quaternary deposits. 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 (maximum value reported from sedimentary rock environment) for the worst case scenario down to 0.001 mD (sealing faults 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 (open fault) case, while for the 0.001 mD (sealing fault) case the pressure buildup is confined within the primary caprock. The results also show that, approximately 03-5.0 bar overpressure can be transmitted to the base Chalk Group when the fault permeability is above 1.0 mD. (C) 2014 Elsevier Ltd. All rights reserved.

Large scale CO2 storage has previously been considered for the Vedsted structure located in the Northern part of Jylland in Denmark. Pressure buildup in the Gassum reservoir and transmission to the shallower Chalk Group where the brine-fresh water interface resides need to be investigated as part of site qualification, as overpressure can push brine into the fresh water zone and thereby affecting aquifer performance. Pressure transmission from the reservoir into the surrounding formations, when fractures and faults are ignored, will depend on the properties and thickness of the sealing rock. The most important property to be considered is caprock compressibility and permeability. Laboratory experiments on centimeter-scale plugs and dynamic sonic velocity data from relevant shale formations in Denmark indicate that shale compressibility is lower than often assumed for reservoir simulation studies. 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 x 10(-5) bar(-1)) normally used for reservoir simulation studies. The consequences of this lower compressibility are investigated in a simulation case study and the results indicate that higher overpressure is created in the reservoir and the caprock. 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 caprock permeability is measured on core samples using a geotechnical method of constant rate of strain (CRS) experiments which seem to match the modeled permeability data for the Fjerritslev Formation. We found an average vertical permeability of 0.1 mu D for the Fjerritslev Formation from the samples measured. 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 of 0.1 mu D. Injecting 60 million tons (Mt) of CO2 at a rate of 1.5 Mt/year into the Gassum Formation for 40 years indicates that, with permeability above 1.0 mu D, overpressure can be transmitted through the 530 m thick Fjerritslev Formation caprock and further up into the overburden layers. (C) 2014 Elsevier Ltd. All rights reserved.

The Fjerritslev Formation in the Norwegian–Danish Basin forms the main seal to Upper Triassic–Lower Jurassic sandstone reservoirs. In order to estimate the sealing potential and rock properties, samples from the deep wells Vedsted-1 in Jylland, and Stenlille-2 and Stenlille-5 on Sjælland, were studied and compared to samples from Skjold Flank-1in the Central North Sea. Mineralogical analyses based on X-ray diffractometry (XRD) show that onshore shales from the Norwegian–Danish Basin are siltier than offshore shales from the Central Graben. Illite and kaolinite dominate the clay fraction. Porosity measurements obtained using helium porosimetry–mercury immersion (HPMI), mercury injection capillary pressure (MICP) and nuclear magnetic resonance (NMR) techniques on the shale samples show that MICP porosity is 6–10% lower than HPMI or NMR porosity. Compressibility, from uniaxial loading, and elastic wave velocities were measured simultaneously on saturated samples under drained conditions at room temperature. Uniaxial loading tests indicate that shale is significantly stiffer in situ than is normally assumed in geotechnical modelling. Permeability can be predicted from elastic moduli, and from combined MICP and NMR data. The permeability predicted from Brunauer–Emmett–Teller (BET)-specific surface-area measurements using Kozeny’s formulation for these shales, being rich in silt and kaolinite, falls in the same order of magnitude as permeability measured from constant rate of strain (CRS) experiments but is two–three orders of magnitude higher than the permeability predicted from the 1998 model of Yang & Aplin, which is based on clay fraction and average pore radius. When interpreting CRS data, Biot’s coefficient has a significant and systematic influence on the resulting permeability of deeply buried shale.

Equivalent pore radius links permeability and porosity of a porous medium. This property can be calculated from specific surface and porosity data measured in the laboratory. We can obtain porosity information from logging data but specific surface information can only be obtained from laboratory experiments on cuttings or core samples. 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 shale intervals. This relationship establishes the possibility of calculating equivalent pore radius from logging data.We used cuttings samples and available well logs to characterize Cenozoic, Cretaceous and Jurassic shale sections in the Skjold Flank-1 well of Danish North Sea. Logging data and well reports were used to select 31 shale cuttings samples and experimental data for porosity, grain density and BET specific surface were obtained from these samples using kaolinite and smectite as reference. The cuttings samples were also characterized with respect to mineralogical composition, content of organic carbon and cation exchange capacity.Equivalent pore radius was calculated from porosity and BET data. It varies from 5 nm for some Cretacous and Jurassic shale samples to about 25 nm in some Cenozoic samples. Pore radius is controlled by shale mineralogy and the degree of compaction.We found exponential relationships between equivalent pore radius and elastic moduli, and these empirical relationships were used to calculate equivalent pore radius for the Cenozoic, Cretaceous and Jurassic shale sections in Skjold Flank-1 well from elastic moduli. Elastic moduli were 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. Cross plots of the equivalent pore radius with neutron porosity and gamma ray data separate the Cenozoic shale section with high equivalent pore radius from Cretaceous and Jurassic sections. (C) 2013 Elsevier B.V. All rights reserved.

Several authors have predicted permeability of shales either through laboratory measurements and or from field data using various empirical relations. A critical literature review by Mondol et al., (2008) on available permeability models, concluded that none of the existing models is ideal and all need to be calibrated and validated through a much larger permeability database of well-characterized mudstones. His results on smectite and kaolinite aggregates suggest that the permeability of smectitic clays may be up to five orders of magnitude lower than that of kaolinitic clays with the same porosity, density, velocity or rock mechanical properties. Mari et al., (2011) described a methodology for obtaining a permeability log based on acoustic velocities Vp and Vs, porosity φ, P-wave attenuation and frequency, their calculation of the specific surface S of the formation was based on the relationship between porosity φ, Vp/Vs and S proposed by Fabricius et al. (2007). Fabricius (2011) indicate that pore radius and thus permeability of shale in the depth interval of mechanical compaction may be predicted from porosity and sonic velocity. In this work we are presenting the empirical equations developed from experimental data that can be used to predict pore radius and permeability of shale from sonic velocity data measured in the field.

Permeability is often very difficult to measure or predict in shale lithology. In this work we are determining shale permeability from consolidation tests data using Wissa et al., (1971) approach and comparing the results with predicted permeability from Kozeny’s model. Core and cuttings materials were obtained from Fjerritslev shale Formation in Juassic interval of Stenlille and Vedsted on-shore wells of Danish basin. The calculated permeability from specific surface and porosity vary from 0.09 to 48.53 µD while that calculated from consolidation tests data vary from 1000 µD at a low vertical effective stress to 9 µD at high vertical effective stress of 100 MPa. The indirect permeability calculated from consolidation tests falls in the same magnitude at higher vertical effective stress, above 40 MPa, as that of the Kozeny model for shale samples with high non-clay content ≥ 70% but are higher by two to five orders of magnitudes at lower vertical effective stress below 40 MPa as the content of clay minerals increases causing heterogeneity in shale material. Indirect permeability from consolidation can give maximum and minimum values of shale permeability needed in simulating fluid flow in shale useful in assessing their integrity for CO2 storage, gas shale exploitation and other engineering applications.

Stratigraphical variation of shale petrophysical properties in the Central North Sea was studied by laboratory analysis of cuttings samples and compared to wireline logging data obtained from Skjold Flank-1 well, Skjold field in the Danish North Sea. The logged section is split into six depth intervals based on wireline log pattern, and with reference to the mud log, cuttings samples were selected. The shallowest intervals (1–3) are silty shale. Interval 2 is rich in organic material. Interval 4 comprises of chalk and underlying calcareous shale. Interval 5 is shale with sand stringers; whereas interval 6 is mainly shale. X-ray diffraction analysis reveals the dominance of inter-layered smectite/illite in interval 1–3 and upper part of interval 4, whereas illite dominates interval 5 and 6. Other minerals include kaolinite, chlorite, quartz, calcite, Opal-CT, dolomite and plagioclase. Mineralogical variation is reflected in cation exchange capacity, BET specific surface, and grain density. Shales vary in total organic carbon, radioactivity, carbonate content, porosity and modeled permeability. Cross plots of logging data splits intervals according to mineralogy, porosity, modeled permeability, and induration. The most effective of intervals splitting is obtained by cross-plotting shear velocity and gamma ray.