The growing demand for energy provides an incentive to pursue unconventional resources. Among these resources, tight gas and shale gas reservoirs have gained significant momentum because recent advances in technology allowed us to produce them at an economical rate. More importantly, they seem likely to contain a significant volume of hydrocarbon. There are, however, many questions concerning hydrocarbon production from these unconventional resources. For instance, in tight gas sandstone, we observe a significant variability in the producibilities of wells in the same field. The heterogeneity is even present in a single well with changes in depth. It is not clear what controls this heterogeneity. In shale gas, the pore connectivity inside the void space is not well explored and hence, a representative pore model is not available. Further, the effects of an adsorbed layer of gas and gas slippage on shale permeability are poorly understood. These effects play a crucial role in assigning a realistic permeability for shale in-situ from a laboratory measurement. In the laboratory, in contrast to in-situ, the core sample lacks the adsorbed layer because the permeability measurements are typically conducted at small pore pressures. Moreover, the gas slippages in laboratory and in-situ conditions are not identical. The present study seeks to investigate these discrepancies. Drainage and imbibition are sensitive to pore connectivity and unconventional gas transport is strongly affected by the connectivity. Hence, there is a strong interest in modeling mercury intrusion capillary pressure (MICP) test because it provides valuable information regarding the pore connectivity. In tight gas sandstone, the main objective of this research is to find a relationship between the estimated ultimate recovery (EUR) and the petrophysical properties measured by drainage/imbibition tests (mercury intrusion, withdrawal, and porous plate) and by resistivity analyses. As a measure of gas likely to be trapped in the matrix during production---and hence a proxy for EUR---we use the ratio of residual mercury saturation after mercury withdrawal (S[subscript gr]) to initial mercury saturation (S[subscript gi]), which is the saturation at the start of withdrawal. Crucially, a multiscale pore-level model is required to explain mercury intrusion capillary pressure measurements in these rocks. The multiscale model comprises a conventional network model and a tree-like pore structure (an acyclic network) that mimic the intergranular (macroporosity) and intragranular (microporosity) void spaces, respectively. Applying the multiscale model to porous plate data, we classify the pore spaces of rocks into macro-dominant, intermediate, and micro-dominant. These classes have progressively less drainage/imbibition hysteresis, which leads to the prediction that significantly more hydrocarbon is recoverable from microporosity than macroporosity. Available field data (production logs) corroborate the higher producibility of the microporosity. The recovery of hydrocarbon from micro-dominant pore structure is superior despite its inferior initial production (IP). Thus, a reservoir or a region in which the fraction of microporosity varies spatially may show only a weak correlation between IP and EUR. In shale gas, we analyze the pore structure of the matrix using mercury intrusion data to provide a more realistic model of pore connectivity. In the present study, we propose two pore models: dead-end pores and Nooks and Crannies. In the first model, the void space consists of many dead-end pores with circular pore throats. The second model supposes that the void space contains pore throats with large aspect ratios that are connected through the rock. We analyze both the scanning electron microscope (SEM) images of the shale and the effect of confining stress on the pore size distribution obtained from the mercury intrusion test to decide which pore model is representative of the in-situ condition. We conclude that the dead-end pores model is more representative. In addition, we study the effects of adsorbed layers of CH₄ and of gas slippage in pore walls on the flow behavior in individual conduits of simple geometry and in networks of such conduits. The network is based on the SEM image and drainage experiment in shale. To represent the effect of adsorbed gas, the effective size of each throat in the network depends on the pressure. The hydraulic conductance of each throat is determined based on the Knudsen number (Kn) criterion. The results indicate that laboratory measurements made with N₂ at ambient temperature and 5-MPa pressure, which is typical for the transient pulse decay method, overestimate the gas permeability in the early life of production by a factor of 4. This ratio increases if the measurement is run at ambient conditions because the low pressure enhances the slippage and reduces the thickness of the adsorbed layer. Moreover, the permeability increases nonlinearly as the in-situ pressure decreases during production. This effect contributes to mitigating the decline in production rates of shale gas wells. Laboratory data available in the literature for methane permeability at pressures below 7 MPa agree with model predictions of the effect of pressure. / text

The Middle Jurassic Entrada Sandstone of the Four Corners region, USA, is composed predominantly of very fine-grained, red, silty sandstone with poorly defined sedimentary structures. The origin of this facies is enigmatic, even though it is common both on the Colorado Plateau and globally, and is spatially situated between deposits recording unambiguous marine and aeolian environments. Eleven sections were measured along an 85 km transect from the Blanding Basin in southeastern Utah to the San Juan Basin in northwestern New Mexico. Outcrop and laboratory analyses distinguish eight facies: (1) silty shale, (2) shallow subaqueous reworked, fine- to medium-grained sandstone, (3) brecciated, very fine-grained sandstone, (4) crinkly laminated, very fine-grained sandstone with preserved wind ripples and abundant silty laminae, (5) weakly laminated, fine-grained sandstone with occasional silty laminae, (6) planar-laminated, fine-grained, wind-rippled sandstone, (7) cross-stratified, fine- to medium-grained aeolian cross-stratified sandstone, and (8) micritic limestone. Lateral and vertical relationships of these facies show a proximal to distal transition from cross-bedded wind-lain facies to loess-dominated sabkha facies with increasing abundance of water-lain facies basinward. The well known Todilto Limestone (facies 8) is situated stratigraphically below loess-dominated sabkha facies (facies 4 and 5) within the Entrada Sandstone, reinforcing previous interpretations that the unit represents a catastrophic flooding event and not a local groundwater flux. / text

The Central Cordillera and Eastern Cordillera of the northern Andes form the western and eastern flanks of the north-trending Middle Magdalena Valley basin. Previous estimates for the timing of initial exhumation of the two cordilleras range from ~100 to ~10 Ma. Accurately constraining the spatial and temporal distribution of deformation in Colombia has implications for the shortening history of the Andean convergent margin and the prediction of rapid lateral facies changes in sedimentary basins in close proximity to sediment sources. This study applies sandstone petrographic point counts, field sedimentological analyses of basin fill, and paleocurrent measurements of trough cross-stratification, clast imbrication, and flute casts to provide new insights into the tectonic history of the flanks of the Middle Magdalena Valley basin. Between the lower and upper Paleocene strata of the Lisama Formation, paleocurrent orientations show a shift from northward to eastward transport. This change in sediment dispersal coincides with a shift from a cratonic (Amazonian) to orogenic (Andean) sediment source, as recorded by published U-Pb detrital zircon geochronological results (Nie et al. 2010), suggesting initial uplift of the Central Cordillera by mid-Paleocene time. Later in the basin’s history, establishment of an alluvial-plain system with meandering-channel deposits is recorded in lower–middle Eocene strata of the lower La Paz Formation. Consistent eastward paleocurrents characterize mid-Paleocene through uppermost Eocene strata, indicating a continuous influence of western sediment source areas. However, within the upper middle Eocene succession (~40 Ma), at the boundary between the lower and upper La Paz Formation, sandstone compositions show a dramatic decrease in lithic content. This compositional change is accompanied by a facies shift to amalgamated fluvial channels, reflecting changes in both the composition and proximity of the western sediment source. We attribute these changes to the growing influence of the exhumed La Cira/Infantas paleohighs off the western flank of the present-day Nuevo Mundo syncline. In the uppermost Eocene strata of the Esmeraldas Formation, paleocurrents show a switch to dominantly westward transport that persisted through the Neogene. In addition, deposits show a contemporaneous decrease in the amount of coarse-grained channel deposits. These changes are interpreted to reflect the onset of exhumation in the Eastern Cordillera. The lack of a significant change in sandstone compositions at this boundary suggests a compositional similarity between strata uplifted by the Lisama structure and the Eastern Cordillera. These data support and further refine previous thermochronologic and provenance studies which suggest that uplift-induced exhumation of the Central Cordillera and Eastern Cordillera commenced by mid-Paleocene and late Eocene–early Miocene time, respectively. / text

Gas wells suffer a decrease in productivity because of the formation of a liquid hydrocarbon “condensate” in the near wellbore area. This "condensate" forms near producing wells when the flowing pressure is below the reservoir fluid's dew point. Several methods have been shown to temporarily alleviate this problem, but eventually the condensate bank reforms and the productivity again decreases. The use of surfactants to alter the near wellbore wettability to neutral wetting is a potential longer term solution to liquid blocking in these reservoirs. This alteration increases the gas and liquid relative permeabilities and thereby the productivity by reducing the residual liquid saturation. This enhancement allows the accumulated liquid to flow and is durable as long as the wettability alteration is persistent. This solution has been shown to be successful through core flood experiments and field trials in high permeability sandstones, but no improvements had been observed in low permeability cores. As the global demand for energy increases, the petroleum industry has begun to develop unconventional (low permeability) assets, new techniques are needed to maintain and improve their productivity. Liquid blocking in these wells can have a much larger impact on both the gas and condensate production in such low permeability formations. Applying this technique increases both gas and condensate mobility and should increase the economic producing life of these wells. Core flood experiments were conducted to investigate the ability of a chemical treatment to alter the wettability of low permeability sandstones. Previous experimentation did not find any improvement because the increased capillary forces prevented the treatment solution from being easily displaced. This concealed the benefit achieved when the wettability was altered. These experiments recorded smaller relative permeability increases compared to higher permeability core floods, so super critical carbon dioxide was tested as an alternative solvent. While the new treatment was more injectable, it was not as successful at altering wettability. Progress has been made on a solution to liquid blocking in low permeability sandstones, but additional research needs to be completed to further optimize this method. / text

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In systems subjected to long-term loading, subcritical crack growth is the principal mechanism causing the time-dependent deformation and failure of rocks. Subcritical crack growth is environmentally-assisted crack growth, which can allow cracks to grow over a long period of time at stresses far smaller than their failure strength and at tectonic strain rates. The characteristics of subcritical crack growth can be described by a relationship between the stress intensity factor and the crack velocity. This study presents the results of studies conducted to validate the constant stress-rate test for determining subcritical crack growth parameters in Coconino sandstone, compared with the conventional testing method, the double torsion test. The results of the constant stress-rate test are in good agreement with the results of double torsion test. More importantly, the stress-rate tests can determine the parameter A with a much smaller standard deviation than the double torsion test. Thus the constant stress-rate test seems to be both a valid and preferred test method for determining the subcritical crack growth parameters in rocks. We investigated statistical aspects of the constant stress-rate test. The effects of the number of tests conducted on the subcritical crack growth parameters were examined and minimum specimen numbers were determined. The mean and standard deviation of the subcritical crack growth parameters were obtained by randomly selecting subsets from the original strength data. In addition, the distribution form of the subcritical crack growth parameters and the relation between the parameter n and A were determined. We extended the constant stress-rate test technique to modes II and III subcritical crack growth in rocks. The experimental results of the modes I, II and III tests show that the values of the subcritical crack growth parameters are similar to each other. The subcritical crack growth parameter n value for Coconino sandstone has the range of 34 to 38 and the parameter A has the range of 1.02x10⁻² to 6.52x10⁻² m/s. The effect of confining stress, specimen size, and water saturation on subcritical crack growth under mode II loading has also been investigated. Finally strength parameters for Coconino sandstone were determined experimentally, including tensile strength, uniaxial compressive strength, cohesion, internal friction angle, in-plane / our-of-plane shear strength and the fracture toughness under mode I, II, and III loading.