Journal of Unconventional Oil and Gas Resources最新文献

Natural fractures, hydraulically generated fractures, and acid etched fractures have some degree of fracture face roughness that generates flow conductivity. While it has been proven both theoretically and experimentally that fracture conductivity depends on fracture face roughness, there are limited models that can predict fracture conductivity at different closure stresses for these various fracture roughness patterns. In addition, some of the models require detailed statistical and topographical surface profile parameters, which limit their field application.

A numerical model is developed to study the closure of rough surfaces in contact. Both asperities and semi-infinite half-spaces are assumed to be deformable. The mechanical interaction among asperities is accounted for and its effect on the fracture closure is investigated. Asperity failure is also considered in the model and the results are compared to that of perfectly elastic contact. Aperture profiles that are the output of the closure model are used to solve the fluid flow problem and study the effect of closure stress on fracture conductivity.

It is evident in our results that the closure behavior depends on the etching pattern as well as the elastic properties of the surface. The performance of a rough fracture depends on its initial aperture, asperity height distribution, roughness pattern, and the closure stress range. Certain fracture roughness patterns were able to withstand the closure stress while undergoing lower amounts of closure. Our model tends to predict fracture closure and conductivity behavior better than widely used correlations.

This paper discusses the closure of fractures and attempts to shed more light on the performance of such a stimulation technique by comparing the closure behavior of some particular surface patterns. Our model can be used to determine the most optimum fracture system for a given reservoir condition.

Flowback water is usually highly saline and the salt concentration varies by time and well location. Understanding the origin of the flowback salts is essential for evaluating fracturing and flowback processes. In this study, laboratory and field analyses are performed to investigate the origin of the flowback salts. The field data includes the total salt concentration (salinity), individual ion concentration, pH, and dissolved oxygen measured during the flowback process for three wells completed in the Horn River Basin. The rock mineralogy is determined using XRD. The cation exchange capacity (CEC) of shale samples are measured using ammonium acetate method. Water and oil imbibition experiments are conducted for shale samples of different surface-to-volume ratio. The individual ion concentration is measured during the water imbibition experiments using ICP–MS and IC. EDXS analysis is used to investigate the surface of natural fractures.

Noticeable amount of barium found on the surface of natural fractures suggests that the barium in the flowback water primarily originates from the natural fractures. Furthermore, the samples with higher clay content have higher CEC. During the water imbibition process, these samples have higher and faster ion transfer from shale-to-water; suggesting the mobilization of the exchangeable ions from the clays. During the water imbibition experiment, the Na/Cl and K/Cl ratios are initially high and decrease at the later times. Leaching of the exchangeable sodium and potassium ions from the clay minerals is a possible reason for the initial high Na/Cl and K/Cl molar ratios. The dissolution of chloride-bearing components increases the chloride concentration, which decreases the Na/Cl and K/Cl molar ratios at later times. The measured pH is slightly above 8 for all of the flowback water samples. The presence of natural buffer systems such as calcite and dolomite may explain the neutral pH range of the flowback water.

The U.S. natural gas price dropped dramatically in the U.S. after the shale gas revolution. This paper investigated if the change in the structure of the U.S. natural gas market after the revolution is affecting the Japanese and European gas markets. We used the Bai–Perron test to identify the break date related to the shale gas revolution and tested if the market linkages among the U.S., Japanese, and European gas markets changed before and after the statistically determined break date. The result indicated that the U.S. gas market had a price relationship with the international markets for the period before the break date related to the shale gas revolution, but this relationship disappeared for the period after the break date. This result implied that the U.S. gas market became independent after the shale gas revolution and that the price linkage between the U.S. and international gas markets became weaker after the shale gas revolution. The study revealed that the effect of the U.S. shale gas revolution is not yet affecting the international gas markets.

This study was conducted to document and assess the effects of fluid–rock interactions when CO₂ is used to create the fractures necessary to produce hydrocarbons from low-permeability rocks. The primary objectives are to (1) identify and understand the geochemical reactions of CO₂-based fracturing, and (2) assess potential changes in porosity and permeability of formation rock. Autoclave experiments were conducted at reservoir conditions exposing middle Bakken core fragments to CO₂-saturated synthetic formation brine and to supercritical CO₂ (sc-CO₂) only. Ion-milled core samples were examined before and after the reaction experiments using scanning electron microscopy (SEM), which enabled us to image the reaction surface in extreme detail and unambiguously identify mineral dissolution and precipitation.

The most significant change in the reacted samples exposed to the CO₂-saturated brine is dissolution of the carbonate minerals, particularly calcite, which shows severe corrosion. Dolomite grains were corroded to a lesser degree. Quartz and feldspars remained intact, and some pyrite framboids underwent slight dissolution. Additionally, a small amount of calcite precipitation took place, as indicated by numerous small calcite crystals formed at the reaction surface and in the pores. The changes of aqueous chemical composition are consistent with the petrographic observations with an increase in Ca and Mg and associated minor elements, and a very slight increase in Fe and sulfate.

When exposed to sc-CO₂ only, changes observed include etching of the calcite grain surface and precipitation of salt crystals (halite and anhydrite) due to evaporation of residual pore water into the sc-CO₂ phase. Dolomite and feldspars remained intact, and pyrite grains were slightly altered. Mercury intrusion capillary pressure (MICP) tests on reacted and unreacted samples show an increase in porosity when an aqueous phase is present but no overall porosity change with sc-CO₂. The results also show an increase in permeability for brine-reacted samples.

X-ray diffraction (XRD) sample preparation methods were compared for fine grained reservoir rocks. The viability of using a hand ground, smear mount method was investigated compared to the widely used micronized, cavity mount method of sample preparation for quantitative phase analysis. Micronizing a sample before analyzing by XRD has been used successfully to reduce the average crystallite size to 10 μm. However, because of the fine grained nature of shale gas reservoirs, the average crystallite size is already below 10 μm. Therefore, the sample only requires disaggregation of larger particles which is easily accomplished by hand grinding. Samples were prepared using smear and cavity mount methods to compare the differences in quantitative phase abundances determined by Rietveld refinement. In addition, samples of known composition were prepared to assess the accuracy and precision of the methods. Quantitative analysis on whole rock samples shows excellent precision between the methods of sample preparation with an absolute error of ±2.25 wt.% at the 95% confidence level per individual phase. Quantitative analysis on artificially prepared samples using the smear mount method shows both excellent precision and accuracy with an absolute error of ±0.9 wt.% at the 95% confidence level per individual phase. A hand ground, smear mount method is therefore a quantitative and viable method for quickly assessing the mineralogy of shale gas reservoirs and fine grained rocks.

Depleted unconventional gas reservoirs have been proposed reservoirs for long-term storage of anthropogenic CO₂. The injection of CO₂ in such reservoirs may benefit from, (1) the presence of existing infrastructure and right-of-way to reduce sequestration costs, (2) the presence of an existing network of fractures to increase reservoir contact efficiency, and (3) potential to enhanced gas recovery using CO₂. However, there remain significant technical challenges and uncertainties about the behavior of these reservoirs, and how they might respond to CO₂ flooding. Toward addressing those uncertainties, the present study considers results of select experiments intended to improve understanding of the fundamental characteristics of shale matrix and shale interactions with methane and carbon dioxide. Outcrop samples from the low permeability sedimentary Marcellus formations in the Appalachian Basin of the eastern United States were characterized using various analytical techniques, including FTIR, XRD, ICP-OES, TOC analyzer, surface analysis, and pycnometry. FTIR confirmed CO₂ adsorption by appearance of an absorption band near 2349 cm⁻¹, however, CH₄ absorption band at 1303 cm⁻¹ was comparatively weak. Total organic carbon (TOC) exhibits significant statistical correlation with Cu, K, and Ni, while several other metals (As, Ba, Ca, Cd, Co, Cr, Fe, Mg, Mn, Na, Sr, and Ti) correlated with total inorganic carbon (TIC). Shale adsorption capacities of both CO₂ and CH₄ showed linear relationships to the organic matter content with CO₂ exhibiting consistently higher adsorption capacities than CH₄. At organic matter content greater than 2 wt%, the ratios of adsorption capacity of CO₂ over CH₄ were in a range between 1.3 and 1.9, which is similar to the ratios of critical temperatures between CO₂ and CH₄. This study evaluates the role of various physical and chemical parameters on CO₂/shale and CH₄/shale interaction, and considers implications for sequestration of CO₂ in depleted shale reservoirs.

Many petroleum engineers apply the conventional formation pressure method to certain gas reservoir, especially the abnormally pressured reservoirs which can lead to errors of up to 100% in the original gas in place (OGIP) extrapolation, and there is still lack of 2-order pressure related equation to estimate the OGIP. Through introducing the transformations and Taylor expansion to the material balance equation, a new 2-order pressure related equation to calculate the OGIP is established; this new method gets advantages of conventional formation pressure method and Law of water cutting volume factor. Meanwhile, it modifies the old linear relationship for conventional P/Z’s in normally pressured reservoirs, and it allows direct extrapolation of OGIP in gas reservoirs concerning rock and water compressibility; after applying this new method to two different abnormally pressured reservoirs, comparisons of predicted results with different methods have been given, and the adaptability and affectivity of the new method have been proved.

Both hydraulic fracture permeability and matrix permeability play important roles in the life of gas production. However, the matrix permeability has not yet been understood fully because gas flow within the matrix undergoes a transition from viscous flow to slip flow and Knudsen diffusion. Traditional Darcy law cannot be utilized directly to represent this phenomenon. Thus, understanding the gas flow inside the matrix and how the matrix permeability evolves during gas depletion has been a major research challenge. In this study, an apparent permeability model for shale matrix is developed to reflect the combined impact of flow regimes and effective stress. Flow regimes are defined by the Knudsen number while the effect of effective stress is expressed by the variable porosity and intrinsic permeability based on poroelasticity theory. This model is verified against the experimental data of the permeability for shale plug samples. Then, the apparent permeability is used to couple shale deformation and gas flow within the matrix. The fully coupled model is implemented and solved by Comsol Multiphysics based on finite element method. Numerical simulation results demonstrate that both flow regimes and effective stress have significant impacts on the apparent permeability of the matrix. The apparent permeability for shale matrix undergoes a slight increase at the early time of production and becomes bigger at the later time because of slip flow and Knudsen diffusion. The slippage effect has a critical impact on the apparent permeability when gas pressure drops to a low magnitude and the Knudsen number would be higher than 0.1. However, the intrinsic permeability experiences a declining trend as the effective stress increases during gas production. Sensitivity analyses indicate that both initial intrinsic permeability and initial porosity have more significant effects on the apparent permeability than the bulk modulus of shale matrix.

Merox process is a developed process for natural gas sweetening. However this process has one main disadvantage, which is the fact that carbon dioxide in the feed gas consumes the sorbent solution. High efficiency of carbonate based solutions for removal of bulk of CO₂ from natural gas is a well-known fact. The alkalinity is important in removal of acid gases by potassium carbonate solution. The main idea behind this work was to investigate the possibility of inhibition of Merox solution consumption by a synergy between Merox and carbonate based sweetening processes. In this study, a carbonate based sweetening process is simulated using Aspen Plus simulator for sweetening the natural gas produced in one of gas fields located in Iran. The effects of addition of sodium hydroxide to the solution on the gas sweetening performance and efficiency are investigated. It is revealed that modifying the solution of this process using sodium hydroxide increases the capacity of the solution in removing acid gases.