Unconventional Natural Gas Reservoirs Research Articles

Fractal Evolution Characteristics on the Three-Dimensional Fractures in Coal Induced by CO2 Phase Transition Fracturing

To analyze the transformed effect of three-dimensional (3D) fracture in coal by CO2 phase transition fracturing (CO2-PTF), the CO2-PTF experiment under a fracturing pressure of 185 MPa was carried out. Computed Tomography (CT) scanning and fractal theory were used to analyze the 3D fracture structure parameters. The fractal evolution characteristics of the 3D fractures in coal induced by CO2-PTF were analyzed. The results indicate that the CO2 phase transition fracturing coal has the fracture generation effect and fracture expansion-transformation effect, causing the maximum fracture length, fracture number, fracture volume and fracture surface area to be increased by 71.25%, 161.94%, 3970.88% and 1330.03%. The fractal dimension (DN) for fracture number increases from 2.3523 to 2.3668, and the fractal dimension (DV) for fracture volume increases from 2.8440 to 2.9040. The early dynamic high-pressure gas jet stage of CO2-PTF coal influences the fracture generation effect and promotes the generation of 3D fractures with a length greater than 140 μm. The subsequent quasi-static high-pressure gas stage influences the fracture expansion-transformation effect, which promotes the expansion transformation of 3D fractures with a length of less than 140 μm. The 140 μm is the critical value for the fracture expansion-transformation effect and fracture generation effect. Five indicators are proposed to evaluate the 3D fracture evolution in coal caused by CO2-PTF, which can provide theoretical and methodological references for the study of fracture evolution characteristics of other unconventional natural gas reservoirs and their reservoir stimulation.

Optimization of Abnormal Hydraulic Fracturing Conditions of Unconventional Natural Gas Reservoirs Based on a Surrogate Model

Abnormal conditions greatly reduce the efficiency of hydraulic fracturing of unconventional gas reservoirs. Optimizing the fracturing scheme is crucial to minimize the likelihood of abnormal operational conditions, such as pressure channeling, casing deformation, and proppant plugging. This paper proposes a novel machine learning-based method for optimizing abnormal conditions during hydraulic fracturing of unconventional natural gas reservoirs. Firstly, the main controlling factors of abnormal conditions are selected through a hybrid controlling analysis, upon which a surrogate model is established for predicting the occurrence probability of abnormal conditions, rather than whether abnormal conditions happen or not. Subsequently, a machine learning-based optimization algorithm is developed to minimize the occurrence probability of abnormal conditions, acknowledging their inevitability during the fracturing process. The optimal results demonstrate the proposed method outperforms traditional methods, on average. The proposed methodology is more in line with the needs of practical operation in an environment full of uncertainty.

Influence of the memory effect during CO2/CH4 mixed gas hydrate reformation process

The study of the memory effect can help to clarify the mechanisms of synthesis and decomposition of the CO2/CH4 mixed gas hydrate for mixed gas separation, CO2 sequestration, and CH4 recovery from unconventional natural gas reservoirs. To examine the impact of the memory effect on the CO2/CH4 mixed gas hydrate synthesis in terms of induction time, gas consumption rate, change of gas components, and separation factor, we conducted initial and second CO2/CH4 mixed gas hydrate synthesis experiments in a porous medium and deionized water system. The influence characteristics of the memory effect on CO2/CH4 hydrate synthesis under the predesigned decomposition temperatures (5 ∼ 25 °C) and pressures (0.5, 1.0, and 1.5 MPa) were investigated under decomposition times of 0.5 and 1.0 h. Compared to the induction time of the initial synthesis, the induction time of the second synthesis was greatly shortened, reaching a maximum of 87.42%. The induction time decreased with decreasing decomposition temperature and pressure in the same decomposition period. The decomposition time had a large effect on the peak value of the induction time during the second synthesis process. Besides, the memory effect was greatly affected by the decomposition time in depressurization cases, and the 0.5 h decomposition time was significantly better than that of 1.0 h. The memory effect had the strongest promotion effect on the second synthesis when the decomposition pressure and time were 1.0 MPa and 0.5 h, respectively. Furthermore, the memory effect improved the nucleation rate of the CO2/CH4 mixed gas hydrate and increased the amount of CO2 hydrate synthesis to 1.3 times that of the initial synthesis. Also, the memory effect influenced the hydrate to exhibit stronger CO2 selectivity, which provides a novel approach for the separation of mixed gases via the hydrate method.

Cross-scale diffusion characteristics in microscale fractures of tight and shale gas reservoirs considering real gas – mixture – body diffusion – water film coupling

The mechanism of solid fluid coupling in unconventional oil and gas reservoirs is complex, and elucidating the characteristics of cross scale gas seepage has important scientific and engineering significance. This article focuses on the gas seepage characteristics in micro fractures of unconventional natural gas reservoirs, with three main innovations: (a) analyzing the coupling mode between real gas effects and mixed gases; (b) Explored the multi factor control mechanism of bulk gas diffusion in microscale fractures; (c) The mechanism of the influence of water film distribution characteristics in microscale fractures on gas seepage was elucidated. Results show that: (a) For the water saturation of 10% and the methane content of 80%, when the gas pressure in the crack increased from 0.2 MPa to 10 MPa, the continuous flow velocity and slippage flow velocity increased. (b) for the water saturation of 10% and the methane content of 80%, when the mixed gas pressure increases from 0.2 MPa to 0.8 MPa, the bulk gas diffusion rate drops relatively rapidly from 8.40E-22 kg/s to 8.18E-23 kg/s (c) for the water saturation of 10% and the methane content of 80%, when the mixed gas pressure increases from 0.2 MPa to 0.6 MPa, the modified slippage flow rate drops relatively rapidly from 7.47E-21 kg/s to 6.96E-21 kg/s.

The generalized method for estimating reserves of shale gas and coalbed methane reservoirs based on material balance equation

As the main unconventional natural gas reservoirs, shale gas reservoirs and coalbed methane (CBM) reservoirs belong to adsorptive gas reservoirs, i.e., gas reservoirs containing adsorbed gas. Shale gas and CBM reservoirs usually have the characteristics of rich adsorbed gas and obvious dynamic changes of porosity and permeability. A generalized material balance equation and the corresponding reserve evaluation method considering all the mechanisms for both shale gas reservoirs and CBM reservoirs are necessary. In this work, a generalized material balance equation (GMBE) considering the effects of critical desorption pressure, stress sensitivity, matrix shrinkage, water production, water influx, and solubility of natural gas in water is established. Then, by converting the GMBE to a linear relationship between two parameter groups related with known formation/fluid properties and dynamic performance data, the straight-line reserve evaluation method is proposed. By using the slope and the y -intercept of this straight line, the original adsorbed gas in place (OAGIP), original free gas in place (OFGIP), original dissolved gas in place (ODGIP), and the original gas in place (OGIP) can be quickly calculated. Third, two validation cases for shale gas reservoir and CBM reservoir are conducted using commercial reservoir simulator and the coalbed methane dynamic performance analysis software, respectively. Finally, two field studies in the Fuling shale gas field and the Baode CBM field are presented. Results show that the GMBE and the corresponding straight-line reserve evaluation method are rational, accurate, and effective for both shale gas reservoirs and CBM reservoirs. More detailed information about reserves of shale gas and CBM reservoirs can be clarified, and only the straight-line fitting approach is used to determine all kinds of reserves without iteration, proving that the proposed method has great advantages compared with other current methods.

An experimental study of ultra-high pressure water jet-induced fracture mechanisms and pore size evolution in reservoir rocks

Ultra-high pressure water jets (UHP-WJ) rock breaking is a promising technology for developing unconventional natural gas reserves . In this study, rock-breaking experiments were conducted using typical reservoir rock samples such as sandstone , shale, and coal. The failure patterns in rocks after impact by UHP-WJ were analyzed. Moreover, the 3D damage field model of the rock was reconstructed based on CT scanning, and the internal crack distribution was visualized and examined. Furthermore, the fracture mechanisms of three types of reservoir rocks under the UHP-WJ impingement were studied. The results indicate that intergranular fractures produced due to shear stress are the dominant type of fracture in sandstones, tensile failure due to stress wave was the main type of fracture observed in shale, and coal exhibited the double breaking characteristics of stress wave effect and water wedge effect. The fragments size distribution of samples shows the largest fragments in shale, followed by coal, and the smallest fragments are observed in sandstone. Finally, the evolution of rock pore structure before and after the impact of UHP-WJ was monitored by nuclear magnetic resonance (NMR) methods. The results reveal that the micropores transform into mesopores and macropores in the sandstone, where the total porosity increased by 14.3%–24.8%. As the jet pressure exceeds 100 MPa, the porosity of shale increases significantly, such that the total porosity of the shale sample increased by 7.6%–37.1%. The mesopores transform into macropores and fractures with the influence of the water wedge effect in coal samples, resulting in the reduction of mesopores and the increase of macropores, where the total porosity of the coal sample increased by 14.6%–40%. The complexity and heterogeneity of pores were reduced under UHP-WJ with the increasing jet pressure. The findings provide a theoretical reference for optimizing the recovery from unconventional natural gas reservoirs .

Co-production of Tight Gas and Coalbed Methane from Single Wellbore: a Simulation Study from Northeastern Ordos Basin, China

Focusing on vertical multi-layer superimposition of unconventional natural gas reservoirs in coal-bearing strata, research on the co-production of tight gas and coalbed methane from a single wellbore was conducted. This study intended to obtain maximum economic benefit of a single well from multi-layers. According to the vertical combination of tight sandstone and coal in the eastern Ordos Basin, the reservoir combinations were classified into direct contact, fracture connected, and non-contact types. Based on the economic benefit of co-production, the inter-layer interference coefficient and applicability coefficient were established. The productivity of tight gas and coalbed methane co-production from one wellbore was numerically simulated using the black oil model. The results indicated that with increase in reservoir permeability, thickness, and average pressure, as well as the decrease in reservoir differential pressure, the combined gas production increased. Gas production rate from different reservoir combination types can be ranked in the following order: direct contact type > fracture connected type > non-contact type. In addition, with increase in permeability ratio (sandstone permeability vs. coal permeability) and average pressure, as well as with decrease in differential thickness and differential pressure, the co-production applicability increased. In addition, for different reservoir combinations, non-contact type co-production can be the first choice, and the next choice is fracture connected type. The results can be beneficial for conducting co-production choice in different unconventional natural gases superimposed basins.

Organic matter provenance and depositional environment of marine-to-continental mudstones and coals in eastern Ordos Basin, China—Evidence from molecular geochemistry and petrology

Cyclothems, composed of interbedded mudstone, coal and sandstone layers, make up the Taiyuan and Shanxi Formations in the Late Carboniferous to Early Permian in North China under a marine-to-continental depositional environment. The cyclothems act as important fossil energy hosts, such as coalbeds, hydrocarbon source rocks and unconventional natural gas reservoirs. Organic geochemistry and petrology of mudstones and coals in the Taiyuan and Shanxi Formations in the eastern Ordos Basin were studied to reveal the organic matter sources and paleoenvironments. Total organic carbon (TOC) contents vary from 1.1 wt% (mudstone) to 72.6 wt% (coal). The samples are mainly within the oil window, with the Tmax values ranging from 433 to 469 °C. Organic petrology and source biomarkers indicate that the mudstones were sourced from a mixed organic matter input, and terrigenous organic matter predominates over aquatic organic matter. The coals are mostly sourced by terrigenous organic matter inputs. High concentrations of hopanes argue for a strong bacterial input. Some m/z 217 mass chromatograms have peaks at the hopanes' retention times as a result of high hopane to sterane ratios. These hopane-derived peaks do not interfere the identification of the steranes because the hopanes and the steranes have different retention times. Maturity-dependent biomarkers demonstrate that the samples have been thermally mature, which agree with the Tmax values. Anomalously low C29 20S/(20S + 20R) and C29 ββ/(ββ + αα) sterane ratios are present in all the samples, and are interpreted as due to the terrigenous organic matter input or the coal-related depositional environment. In addition, biomarkers and iron sulfide morphology indicate that the organic matter of the mudstones deposited in a proximal setting with shallow, brackish/fresh water bodies. With consideration of preservation of organic matter, the redox conditions are dysoxic. Redox oscillations resulted in the records of oxic conditions in some samples. Finally, the coals and the mudstones mainly generate gas and have poor oil generative potential.

Flowback cleanup mechanisms of post-hydraulic fracturing in unconventional natural gas reservoirs

This work investigates the fracturing fluid cleanup mechanisms of post-hydraulic fracturing in unconventional gas formations by studying a large number of wide-ranging parameters simultaneously.In this work, different scenarios of the cleanup operation of the hydraulic fracturing process are considered. This study consists of investigating the post-fracturing cleanup operation of hydraulically fractured vertical wells (VW) and multiple fractured horizontal wells (MFHWs). Additionally, the impact of soaking time, the range of the matrix permeability, applied drawdown pressure, injected fracturing fluid (FF) volume, fracture spacing and horizontal well length has been investigated by running different sets.Results show that the trend of the impact of relevant parameters for VWs and MFHWs are analogous excepting the matrix permeability, km. That is, in the MFHW base reference set, the effect of matrix permeability on capillary pressure is more significant than that on fluid flow while the reverse is observed for VW. The difference in the impact of km in VWs and MFHWs is attributed to the geometry of the fluid flow towards the production well and different well completion scheme.It is also concluded that the impact of parameters affecting the capillary pressure in the matrix is more significant for MFHWs whereas matrix and fracture mobility pertinent parameters are more important for VWs than MFHWs. As a result, larger matrix capillary pressure values are more vital in the cleanup of MFHWs because of more imbibition of FF into the matrix and subsequently lower conflict between the flow of gas and FF in the fracture.The other part of this research concentrates on the impact of IFT reducing agents on the post-fracturing production in different formations. In hydraulic fracturing operations, these agents are commonly used as an additive in fracturing fluid to facilitate its backflow by reducing Pc and subsequently enhancing gas production. The results of this work recommend that using such agents enhances the gas production rate for ultratight formations but not for tight formations (it reduces the gas production rate). Therefore it is not suggested to use such agents in tight formations.The findings of this work improve the understanding of fracture cleanup leading to better design of hydraulic fracturing operations in unconventional formations.

Fluid saturation evolution with imbibition in unconventional natural gas reservoirs

Hydraulic fracturing plays an important role in developing unconventional natural gas. The large amount of fracturing fluid retention becomes a significant phenomenon in gas fields. Much research has been carried out to explain this mechanism. Imbibition is regarded as one of the important factors and has been investigated extensively. However, the saturation evolution of different types of fluids (liquid, free gas, and trapped gas) has been less researched during imbibition. A porosity experiment combined with an imbibition experiment was conducted to research the fluids-saturation evolution. There are three types of experimental rocks: tight sand, volcanic rock, and shale. The free-gas saturation decreases with the increasing liquid saturation in all samples. However, the sum of these two types of saturation is approximately 100% during imbibition in tight sand. This indicates that the pore space is almost totally filled by liquid and free gas. The sum of these two types of saturation is less than 100% during imbibition in volcanic rock. This indicates that there is trapped gas by liquid. Trapped-gas saturation increases at the early period and decreases at the late period. The sum of these two types of saturation greatly exceeds 100% during imbibition and increases with the imbibition time in shale rocks. This means that there is large amount of extra imbibition liquid. At the same time, the free-gas saturation fluctuates with the increasing liquid saturation. Based on the above results, it can be concluded that tight sand reservoirs have nearly no trapped gas and extra imbibition liquid, volcanic reservoirs have trapped gas and a little extra imbibition liquid, and shale reservoirs have some trapped gas and a large amount of extra imbibition liquid. This research contributes to understanding the fluid saturation evolution during hydraulic fracturing in unconventional natural gas reservoirs.

Down-hole isolation towards high-temperature reservoir using packing elements with swellable thermo-plastic vulcanizates

The well completion and fracturing towards deep unconventional high-temperature (HT) petroleum or natural gas reservoirs is considerably strict to the packer especially packing elements. However, existing packing elements including swellable packers usually are made from Hydrogenated Nitrile (HNBR) or Fluorine rubber (FKM) with drawbacks of great expense and difficult tripping into the horizontal wellbore. This paper proposes a compact isolating solution using swellable Thermo-plastic Vulcanizates (TPVs), which is prepared by blending HNBR, low-cost Polyamide66 (PA66) and Porous Super Absorbent Resin (PSAR) with enhanced nanoparticles. The TPVs were characterized by experiments and the system with Plastic/Elastomer Ratio (PER) of 45:55, tensile strength of 18.6 MPa and elongation at break of 635% upon aging (150 °C) was qualified for the packing element material. A novel enhanced packing element is put forward with corrugated-profile structure to address large-size and over-extrusion issues. The numerical study on packer components was conducted based on TPV constitutive model. The prototype with element length of 2.5–2.6 m was validated in the lab and rated as the sealing of more than 70 MPa. An optional disintegrating casing is adopted to avoid the premature damage risk of packers. For the field trial, the multistage fracturing tubular with improved packers was deployed into the horizontal open hole without severe pipe stuck. The fracturing operation was successfully performed and all packers functioned normally with the maximum pressure differential of 73 MPa. It concludes that the new solution exhibited high strength, heat resistance and structure integrity with low cost over the traditional packers towards HT environment.

Optimization design of hydraulic parameters for supercritical CO2 fracturing in unconventional gas reservoir

Unconventional gas reservoirs are characterized by ultra-low permeability. Such ultra-low permeability can significantly affect the geometry of the fractures being created in the reservoir, as well as bring about challenges with regard to how to effectively mitigate formation damage issues during fracturing. Supercritical CO2 (SC-CO2) fracturing, as an innovative and promising stimulation method, incurs no formation damage, and is capable of effectively improving the reservoir permeability, preventing near-wellbore formation blockage. Taking the effects of adsorption between CO2-shale-CH4 into consideration, a two-phase filtration rate calculation model of SC-CO2 fracturing in unconventional natural gas reservoirs is proposed. Based on physical property equations of a SC-CO2 fluid, and considering the internal fluid energy, the change in flow work, and the filtration and adsorption characteristics of SC-CO2-shale, temperature and pressure field models were built inside the wellbore and fracture of SC-CO2 fracturing, as was a two-phase flow model of SC-CO2 fracturing fluid carrying proppant in a fracture under an unsteady state. The calculation results show that the temperature and pressure of the fracturing fluid in the wellbore increase with the depth of the well. The temperature of the SC-CO2 fluid in the fracture increases with the increase in fracture length, and eventually reaches close to the original formation temperature, whereas the pressure of fluid CO2 in the fracture decreases with an increase in the fracture length. The hydraulic parameters of SC-CO2 fracturing are optimized, such as the CO2 injection temperature, pumping rate, proppant density, and diameter. According to the proppant embankment profile, the method of increasing the proppant concentration in small steps and the optimization of the proppant pumping process satisfy the fracture propping requirements.

A mathematical model for gas and water production from overlapping fractured coalbed methane and tight gas reservoirs

With the continuous expansion, exploration and development of unconventional natural gas resources, mainly coalbed methane, shale gas and tight gas, some areas overlapped by two or three types of unconventional natural gas reservoirs are explored, e.g., the Linxing, Shilou and Linfen blocks located in the east margin of the Ordos Basin, China. Gas extraction from an individual reservoir becomes not economic as gas resources are not fully recovered; thus, gas coproduction from two or multiple layers is an effective method for improving gas production. In this work, a mathematical model of gas and water two-phase flow for the coproduction of coalbed methane and tight gas is developed. The adsorption characteristics, stress-sensitive and matrix shrinkage effects on coal permeability, and the stress-sensitive effect of tight sandstone are all considered in the model. The gas production related parameters, such as bottom hole flowing pressure, reservoir pressure differences, reservoir properties (e.g., permeability, cleat compressibility of coal, and Langmuir isotherm parameters) are discussed and compared with different geological conditions. The results show that the gas and water flow from the coalbed and sandstone reservoirs show no interference between each other under a constant pressure drainage system; the sandstone reservoirs show a fast pressure drawdown with a high gas production rate decline, while the coalbed reservoir is slow in pressure drawdown and the gas production rate increases gradually. The properties of a specific reservoir have a great influence on its own gas production performance, but with no influence on the other reservoirs. It was found that a lower constant drainage pressure should be adopted in the case of stress-sensitive effects, and coal with a lower cleat compression coefficient and Poisson's ratio value is better for higher gas production. The production contribution from each layer can be acquired if a specific production rate is set. If the reservoir pressure difference between the two reservoirs is too high (for instance at least > 3 MPa in the cases studied in this work), gas and water intrusion may happen, but the reservoirs would be balanced quickly. Thus, the coproduction of coalbed methane and tight gas from one well bore is feasible, and more work should be conducted on proposing a proper drainage strategy to improve the gas resource recovery efficiency in coal-bearing strata.

Theory, technology and prospects of conventional and unconventional natural gas

Abstract The development of natural gas in China has entered a golden and leap-forward stage, which is a necessary bridge to clean energy. This in-depth study on the status quo, theory, technology and prospect of natural gas development shows: (1) The global remaining proven recoverable reserves of natural gas are 186×1012 m3 and the reserves-production ratio is 52.4, indicating a solid resource base for long-term and rapid development. (2) Ten formation and distribution laws of conventional and unconventional natural gas reservoirs have been proposed. In terms of exploration geology, the theory of conventional “monolithic” giant gas fields with different gas sources, and an unconventional gas accumulation theory with continuous distribution of “sweet areas” in different lithologic reservoirs have been established; in terms of development geology, a development theory of conventional structural gas reservoirs is oriented to “controlling water intrusion”, while a development theory of unconventional gas is concentrated on man-made gas reservoirs. (3) With the geological resources (excluding hydrates) of 210×1012 m3 and the total proven rate of the resources less than 2% at present, the natural gas in China will see a constant increase in reserve and production; by 2030, the proven geological reserves of natural gas are expected to reach about (6 000− 7000)×108 m3 the production of conventional and unconventional natural gas each will reach about 1 000×108 m3 and the gas consumption will reach 5500×108 m3. The dependence on imported natural gas may be 64% by 2030, and 70% by 2050. (4) Ten measures for future development of natural gas have been proposed, including strengthening exploration in large-scale resource areas, increasing the development benefits of unconventional gas, and enhancing the peak adjusting capacity of gas storage and scale construction of liquified natural gas.

Study on filtration patterns of supercritical CO2 fracturing in unconventional natural gas reservoirs

AbstractTaking the supercritical CO2 (SC‐CO2) Joule–Thomson coefficient and the effects of adsorption between CO2‐shale‐CH4 into consideration, a two‐phase filtration rate calculation model of SC‐CO2 fracturing in unconventional natural gas reservoirs is proposed. With the help of an experimental apparatus of fluid filtration in shales, it has been found that the theoretical calculation and experimental measurement have an absolute error of 3.31% of the steady filtration rate under specific conditions. Under different pressure differentials between the reservoir and the fracture, the absolute average error of the calculated filtration rate is 2.53%, compared with the experimental data. The filtration of the SC‐CO2 fracturing in an unconventional natural gas reservoir is characterized by the filtration rate, which gradually decreases with time, and the rate of its decrease tends to reach equilibrium in the late stage. The funnel‐like pressure distribution occurs near the fracture during the transmission of the filtration pressure. A non‐linear relationship exists between the filtration rate and the permeability, which indicates that higher permeability enlarges the effective range of the fracturing fluid pressure as well as the invasion region. Moreover, the steady filtration rate and the pressure drop magnitude present a nearly linear increase with the increasing filtration pressure differential. In the site operation of the SC‐CO2 fracturing, the injection temperature, pressure, and pump rate can be optimized using the proposed chart. Thickening of the SC‐CO2 fracturing fluid can effectively decrease the filtration rate, and thus development of thickened SC‐CO2 fracturing fluid systems that prevent formation damage is needed. © 2017 Society of Chemical Industry and John Wiley & Sons, Ltd.

Application of Raman spectroscopy analysis in unconventional natural gas reservoirs – density and pressure dependence on Raman signal intensity

Application of Raman spectroscopy analysis in unconventional natural gas reservoirs – density and pressure dependence on Raman signal intensity

Effect of Surfactant Adsorption on the Wettability Alteration of Gas-Bearing Shales

Abstract Water loss in low permeability reservoirs during hydraulic fracturing well completions typically results in a decrease in natural gas production due to capillary trapping near the fractures. Shale gas reservoirs, however, have shown a trend of improved gas production with increased loss of completion fluids to the shale. This nonintuitive relationship between water imbibition and enhanced gas production in shale gas reservoirs is explored here through investigation of shale wettability alteration after exposure to two surfactants, one cationic and one anionic, commonly used in hydraulic fracturing fluids. Wettability alteration of samples from two unconventional natural gas reservoirs, the Marcellus and Collingwood shales, was examined in this study. In addition to individual surfactant solutions, 1:1 mixtures of cationic and anionic surfactants were examined at concentrations above and below critical micelle concentration levels. This study provides deeper understanding of adsorption mechanisms ...

CDEM-based analysis of the 3D initiation and propagation of hydrofracturing cracks in heterogeneous glutenites

Unconventional natural gas reservoirs usually have composite or heterogeneous microstructures, and heterogeneity has significant influence on the initiation and propagation of hydrofracturing cracks. Numerical simulation has advantages over in situ or experimental studies in the examination of the integrate hydrofracturing process. Many numerical modelling studies have been conducted to investigate the patterns of underground hydraulic fracturing. Unfortunately, few models have adequately simulated the 3D dynamic hydraulic fracturing process while maintaining accurate heterogeneous structures. This study adopted numerical simulation to investigate the processes of the initiation and the propagation of cracks in a heterogeneous material based on the CDEM algorithm, which couples finite and discrete element methods. A numerical model was used to represent the actual heterogeneous structure of a physical specimen. The initiation position and process of propagation of cracks influenced by geostress differences and heterogeneity are discussed. The efficiency of the simulation work was verified by the 3D reconstruction models in terms of the experimental results. The results indicated that material heterogeneity has considerable effect on crack initiation, but that crack propagation is controlled primarily by the geostress ratio.

Modeling of yield-power-law fluid flow in a partially blocked concentric annulus

Horizontal well is one of the most effective ways of developing unconventional oil and natural gas reservoirs. During horizontal well drilling, a stationary cuttings bed forms on the low-side of the wellbore. Formation of the bed is undesirable and has detrimental effect on wellbore hydraulic and drilling performance. Hydraulic optimization of the process strongly depends on accurate prediction of bed height and frictional pressure loss. Therefore, it is necessary to investigate hydraulic characteristics of horizontal wellbore with cuttings bed, which can be represented by partially blocked concentric annulus when centralizers are used with drillpipe.In this study, flow in a partially blocked concentric annulus is investigated using Computational Fluid Dynamics (CFD) approach. CFD simulation results are validated using established numerical solutions and experimental measurements obtained from concentric annulus. The analysis is performed for laminar flow of yield-power-law (YPL) fluid. Pressure loss and wall shear stress acting on the cuttings bed are obtained from CFD simulation. Results show significant variation in bed shear stress in the lateral direction. Hence, average bed shear stress (τ¯bed) is used to analyze the result. Unexpected τ¯bed trend is observed when bed height is increased at constant flow rate. As bed height increases, τ¯bedslightly decreases at low bed heights until it reaches the inner pipe. For bed height greater than annular clearance, τ¯bedtrend is normal, it increases with bed height.Existing hole cleaning models require accurate prediction of τ¯bedand pressure loss in partially blocked concentric annuli. Therefore, combining existing non-circular duct modeling approach and simulation data, simplified models are developed to predict pressure loss and τ¯bed. Model predictions show reasonable agreement with simulation results. Maximum discrepancy of ±10% has been observed.

On the pressure-saturation path in infinite-acting unconventional liquid-rich gas reservoirs

Unconventional liquid rich natural gas reservoirs exhibit a number of unique technical challenges, including ultra-low rock permeability, which can lead to prolonged periods of infinite-acting flow. Despite this, traditional production data analysis techniques often assume boundary-dominated conditions, which may not be experienced by unconventional systems for very long stretches in their productive life. Analysis of two-phase flow and well production often relies on the use of two-phase pseudo-variables calculations for which the fluid saturation-pressure relationship must be estimated a priori. The de-facto assumption is that such a priori reservoir saturation-pressure dependency can be acquired from available constant volume depletion (CVD) or constant composition expansion (CCE) laboratory test results. As a result, the influence of reservoir characteristics or drawdown conditions on saturation-pressure path has not been rigorously investigated in general; and even less for the particular case of infinite-acting reservoir systems under linear flow regime, which is the most commonly observed flow regime in multi-fractured horizontal wells. In the present work, a recently developed semi-analytical solution for the multiphase black-oil formulation, which considers both pressure and liquid saturation as independent variables, is employed to investigate the influence of reservoir and well conditions on saturation-pressure path in linear infinite-acting liquid rich gas systems. Here, the effects of constant bottomhole flowing pressure, initial reservoir pressure, and relative permeability characteristics on pressure-saturation path are explored in a reservoir system. Results are compared to constant composition expansion (CCE) and constant volume depletion (CVD) tests, which are routinely invoked to estimate saturation-pressure path, and it is demonstrated that these tests provide very poor estimations of saturation-pressure path for all cases considered. In addition, saturation-pressure paths exhibit significant sensitivity to the parameters investigated, as a result of the significant interplay between liquid dropout and phase mobility. Finally, following the results of the sensitivity study, we use the concept of the compositionally-extended black-oil formulation to further study the physical mechanisms that control saturation-pressure path behavior, which are elucidated through an investigation of the in situ and flowing compositions of surface gas and surface oil pseudocomponents. The results of this paper indicate that traditional methods for estimation of the saturation-pressure path in liquid-rich unconventional systems cannot account for the influence of system parameters on liquid-phase dropout and condensate accumulation. Furthermore, production data analysis techniques must account for these dependencies to develop reliable reservoir forecasts and reserve estimations.