Gas Formations Research Articles

Petrophysical characteristics of Silurian and Ordovician shale gas formations in the Baltic Basin (Northern Poland)

This paper presents findings from the study into the relationships between the laboratory- and well log-derived data (including the comprehensive well-log interpretation data) on petrophysical properties of the Silurian and Ordovician shale gas formations in the Baltic Basin (North Poland). Approximately 70 samples of mudstone were examined in laboratory experiments to determine total and effective porosity; bulk, grain, and rock density; total organic carbon; physical permeability; total pore area, pore distribution; and mineral components. Some rock samples were further investigated using mercury injection porosimetry, helium porosimetry, dual liquid porosimetry, NMR, N2 adsorption/desorption, rock-eval pyrolysis, and XRD to obtain the targeted petrophysical information from heterogeneous claystone/mudstone and their organic matter. Natural radioactivity, bulk density, total porosity, volume of kerogen, and other parameters were determined from the continuous curves plotted from the earlier depth matched well logging data, which were used to account for differences between vertical resolution of well logs and the point data obtained from the laboratory. The goal of this study was to provide a comprehensive characterization of the Silurian and Ordovician shale gas formations in Northern Poland to support the thesis about their heterogeneity.

Interval inversion based well log analysis assisted by petrophysical laboratory measurements for evaluating tight gas formations in Derecske through, Pannonian basin, east Hungary

The evaluation of Hungarian tight gas formations requires the use of innovative interpretation technologies because of diverse geological environment, heterogeneous dataset including several variables measured with different accuracies, and reservoirs under varying petrophysical conditions. Conventional well logging methods based on the use of limited number of wireline logs make only a quick-look interpretation, in which a limited number of unknowns is determined, and there is a non-negligible risk for occurrence of ambiguity. In order to increase the overdetermination (data-to-unknowns) ratio and the estimation accuracy and reliability, all suitable well logs are to be jointly processed in a more effective manner. To estimate the total organic carbon content together with porosity, water saturation, shale content and rock matrix volumes with higher accuracy, a new inversion methodology is introduced that is tested in tight gas reservoirs. A differential evolution algorithm-based interval inversion method is developed that is combined by nano-permeability and high precision porosity laboratory measurements for the detection and evaluation of Hungarian tight gas reservoirs. Spectral gamma-ray, neutron-porosity and electric resistivity logs are jointly analyzed using the interval inversion approach. By solving a highly overdetermined inverse problem, the effective porosity, water- and gas saturation, shale and sand content, as well as the kerogen volume are estimated in a reliable inversion procedure. The silt and clay content of Miocene tight gas formations are separated and both determined by inversion, while the total organic carbon content is derived from the inversion results. The permeability log is directly derived from the inverted porosity values using the local porosity versus permeability relation established by multi-well core analysis. The combination of in situ wireline log data analysis and porosity and nano-permeability laboratory measurements is shown to be advantageous for a more reliable interpretation of unconventional hydrocarbon formations. An added advantage of the interval inversion method is the calculation of depth dependent errors of the estimated petrophysical quantities. It is shown that total organic carbon and other volumetric parameters can be determined with high accuracy in one interpretation procedure. In the Derecske basin, East Hungary, gas indications are confirmed by interval inversion, that were previously made it probable according to measurements made on poor core samples and rather noise-sensitive local well logging inversion procedure. The joint evaluation of new core data and original wireline logs using the proposed methodology may reveal further potential tight gas resources in the studied area. The Hungarian case study confirms that the suggested workflow may serve a new alternative for an improved evaluation of tight gas formations in different other hydrocarbon fields.

Colmatating of productive gas formations while drilling wells with abnormally lower hydrostatic pressures

Today the pressures in productive gas collectors on the Dnieper-Donets rift are considerably lower than hydrostatic ones. Opening such formations while drilling is a challenging task in terms of preventing losses and differential pressures. In order to solve the problem, one needs to improve the methods of effective temporary colmation of productive formations with acid-soluble materials under the conditions of abnormally low formation pressures during drilling on fields with late terms of development. Traditional algorithms of lost circulation control in abnormally low reservoir pressure, developed by leading world services companies, often turn out to be unworkable. In order to conduct the lost circulation control, one often chooses colmatants, which totally align with the principles of ideal packaging, however do not meet the criterion of strength or resistance to significant differential pressure. As a result, in the course of the subsequent drilling there can be another circulation loss in already colmated layer. In Ukraine the lost circulation control sphere is being developed by means of selecting colmatants according to a new principle. The article has proposed the activities for the lost circulation curing and pollution reducing of productive collectors. For this purpose the generalized characteristic-criterion of colmatants has been developed and used. The criterion got a name “flexibility”, i.e. a deformation, compaction and penetration (into porous-fissured medium) capability under immense pressure. With the help of the criterion the set of particular colmatant have been chosen; also, principles of colmatant mixtures selection under the relevant geological and mining conditions have been identified. In many cases, there is no need to calculate the physical parameters of the formation and the circulation loss crack due to flexibility of colmatant; one only has to select the optimal concentrations of materials and the periodicity of input these materials to the mud. The developed technology confirms the need to improve the algorithms for circulation loss prevention and curing, primarily for conditions of abnormally low reservoir pressures.

Software development for cloud and internet-of-things (IoT) based remotely controlled four-dimensional (4D) electrical resistivity tomography

Electrical resistivity tomography (ERT) is an important method for exploring oil and gas formations, mineral deposits, and groundwater resources. However, most ERT instruments have limitations such as complicated human–computer interaction, few measurement parameters, difficulties in remote monitoring, and lack of four-dimensional (4D) exploration functions. To overcome these limitations, in this study we proposed and developed software for a remote control 4D ERT system based on a cloud platform and Internet of Things (IoT) technology. Specifically, acquisition device control, channel and control, acquisition control, and remote monitoring systems were designed, with various modules being debugged and optimized multiple times. The system is equipped with a 4G module, through which the collected data are transmitted to the cloud platform to realize real-time, stable, and long-distance data acquisition and transmission. Furthermore, the system realizes remote monitoring, real-time measurement, and other functions via the cloud and IoT technology, thereby providing strong technical support for achieving 4D exploration. The developed system was empirically evaluated by applying it to explore the Gequ Landslide area in Jainca County, Qinghai Province, China. The exploration results indicate that the system software has stable functions and high intelligence; thus it satisfies the requirements for field exploration.

Study on Nuclear Magnetic Resonance Logging T2 Spectrum Shape Correction of Sandstone Reservoirs in Oil-Based Mud Wells.

The oil-based mud filtrate will invade the formation under the overbalanced pressure during drilling operations. As a result, alterations will occur to the nuclear magnetic resonance (NMR) response characteristics of the original formation, causing the relaxation time of the NMR T2 spectrum of the free fluid part to move towards a slower relaxation time. Consequently, the subsequent interpretation and petrophysical evaluation will be heavily impacted. Therefore, the actual measured T2 spectrum needs to be corrected for invasion. For this reason, considering the low-porosity and low-permeability of sandstone gas formations in the East China Sea as the research object, a new method to correct the incorrect shape of the NMR logging T2 spectrum was proposed in three main steps. First, the differences in the morphology of the NMR logging T2 spectrum between oil-based mud wells and water-based mud wells in adjacent wells were analyzed based on the NMR relaxation mechanism. Second, rocks were divided into four categories according to the pore structure, and the NMR logging T2 spectrum was extracted using the multidimensional matrix method to establish the T2 spectrum of water-based mud wells and oil-based mud wells. Finally, the correctness of the method was verified by two T2 spectrum correction examples of oil-based mud wells in the study area. The results show that the corrected NMR T2 spectrum eliminates the influence of oil-based mud filtrate and improves the accuracy of NMR logging for calculating permeability.

Assessing the effect of proppant compressibility on the conductivity of heterogeneously propped hydraulic fracture

Hydraulic fracturing is a technology that is widely used in the development of oil and gas formations. Given that the fracture closure has a strong impact on production, quantifying the resulting fracture conductivity is critical for optimizing treatment design. The goal of this paper is to better understand the influence of the closing stress on the fracture conductivity when the proppant distribution is heterogeneous. In addition to the spatial proppant distribution, the conductivity of the propped fracture is affected by proppant deformation and embedment. Numerical results indicate that compressibility of proppant can significantly change the residual fracture aperture and, consequently, production performance in oil and gas reservoirs

Study on the mechanism and main control factors of lost circulation in deep brittle shale in Changning block

Sichuan Changning block is rich in shale gas resources reservoirs, but the lost circulation problem is prominent during the horizontal drilling process of deep shale gas wells, which seriously restricts the exploration and development of deep shale gas resources in the Changning Block. Aiming at the problem of lost circulation in the drilling process of deep shale gas in Changning well area, the difference of the vertical and horizontal distribution of lost circulation is clarified by comparing the information of deep shale lost circulation in this block. Based on single well logging data and 3D seismic interpretation, the 3D distribution model of shale gas formation fracture, in-situ stress and formation pressure was established. The response relationships among fracture development, in-situ stress distribution, formation pressure and lost circulation in shale formations were studied, and the lost circulation mechanism and main influencing factors of deep shale gas formations in the Changning well area were clarified. The results of the study show that deep shale lost circulations in the Changning well block is prominent and widely distributed longitudinally and horizontally with unclear regularity, and that regional fracture development, in situ stress field and formation pressure have obvious effects on well leaks. The distribution of fractures, in-situ stress field and formation pressure in Changning block have a significant and highly responsive effect on lost circulation. The results of this paper reveal the complex mechanism of deep shale lost circulation in the Changning block and the main influencing factors, and provide a certain scientific basis for prevention and treatment of deep shale reservoir leakage in Changning block.

Development Evaluation and Optimization of Deep Shale Gas Reservoir with Horizontal Wells Based on Production Data

The implementation of horizontal wells is a key to economic development of the deep shale gas reservoir. In order to optimize the key parameters for drilling, stimulation, and the production system, the development effect of a horizontal well in deep shale gas formations was investigated from various aspects in this study. The drilling, fracturing, and production performances of this well were analyzed combining with the geological characteristics. The main technical problems and key factors that restrict the gas well performance and estimated ultimate recovery (EUR) were clarified. Through the integrated study of geology and engineering, the optimization strategies for increasing gas production and EUR are provided. The Z2 area, where the Z2-H1 well is located, has good reservoir physical properties, which bring a high drilling efficiency. However, there are still some problems during its development, such as poor fracture extension both horizontally and vertically, limited stimulated reservoir volume (SRV), rapid production declining, large water production, and serious liquid accumulation. In this study, a comprehensive approach was proposed that can improve single-well production and EUR by optimizing the target position, horizontal section length, pathway, spacing, new drilling and fracturing technology, and production system.

Adsorption and storage characteristics of natural gas in low-permeability porous materials

Shales are generally treated as non-porous formations and are frequently considered as the source rock and the cap layer. Over the past decades, technical breakthroughs in the US such as horizontal drilling, multi-stage hydraulic fracturing, micro-seismic monitoring and multi-well completions have revolutionised the exploitation of shale gas formations. Natural gas in shales is encountered not only as free gas in the pore structure and fractures, but also as adsorbed gas on the pore surfaces. Accurate estimation of the amount of free and adsorbed gas and the precise analysis of the transient flow behaviour in shale gas formations are crucial for predicting production performance, devising or adjusting the production strategy, and fracture design in shale gas reservoirs.Inclusive modelling of the adsorption and desorption processes is quintessential to correctly estimate gas reserves. To ensure that the adsorption mechanism is thoroughly captured, this research considered several isotherm profiles while theoretical results were informed by experimental measurements. Closely matching core flow measurements, the Klotz isotherm model illuminated the adsorption mechanism in shale porous media. Variations in pressure and gas flowrate were deduced at the micro-level. A non-dimensionalisation approach enabled the comparison between micro-scale modelling results with actual core measurements several orders of magnitude apart in spatial and temporal scales. Normalised micro-scale theoretical results, considering the incorporated Klotz isotherm, displayed excellent agreement with actual core measurements shedding light on some of the profound aspects which govern gas flow.

Lightly salted surface waters

Hydraulic Fracturing Hydraulic fracturing uses a water-based mixture to open up tight oil and gas formations. The process is mostly contained, but concerns remain about the potential for surface water contamination. Bonetti et al. found a small increase in certain ions associated with hydraulic fracturing across several locations in the United States (see the Perspective by Hill and Ma). These small increases appeared 90 to 180 days after new wells were put in and suggest some surface water contamination. The magnitude appears small but may require that more attention be paid to monitoring near-well surface waters. Science , aaz2185, this issue p. [896][1]; see also abk3433, p. [853][2] [1]: /lookup/doi/10.1126/science.aaz2185 [2]: /lookup/doi/10.1126/science.abk3433

Improved well logs clustering algorithm for shale gas identification and formation evaluation

The identification of lithology, fluid types, and total organic carbon content are of great priority in the exploration of unconventional hydrocarbons. As a new alternative, a further developed K-means type clustering method is suggested for the evaluation of shale gas formations. The traditional approach of cluster analysis is mainly based on the use of the Euclidean distance for grouping the objects of multivariate observations into different clusters. The high sensitivity of the L2 norm applied to non-Gaussian distributed measurement noises is well-known, which can be reduced by selecting a more suitable norm as distance metrics. To suppress the harmful effect of non-systematic errors and outlying data, the Most Frequent Value method as a robust statistical estimator is combined with the K-means clustering algorithm. The Cauchy-Steiner weights calculated by the Most Frequent Value procedure is applied to measure the weighted distance between the objects, which improves the performance of cluster analysis compared to the Euclidean norm. At the same time, the centroids are also calculated as a weighted average (using the Most Frequent Value method), instead of applying arithmetic mean. The suggested statistical method is tested using synthetic datasets as well as observed wireline logs, mud-logging data and core samples collected from the Barnett Shale Formation, USA. The synthetic experiment using extremely noisy well logs demonstrates that the newly developed robust clustering procedure is able to separate the geological-lithological units in hydrocarbon formations and provide additional information to standard well log analysis. It is also shown that the Cauchy-Steiner weighted cluster analysis is affected less by outliers, which allows a more efficient processing of poor-quality wireline logs and an improved evaluation of shale gas reservoirs.

Modeling product distribution of top-lit updraft gasification

A kinetic model for predicting biochar, producer gas, and tar formations of top-lit updraft (TLUD) gasification was developed. The three main zones within the TLUD gasifier, the pyrolysis, incomplete combustion, and reduction reaction zones, were incorporated into the model and sequentially solved. Validated with experimental data, the model was found capable of predicting biochar yield on pine woodchips at varying airflow rates, biomass moisture contents, and biomass compactness. However, when the particle size was varied, the model underestimated biochar yield. The model also accurately predicted the higher heating value of the producer gas that varied from 3.45 to 3.98 MJ/m3 compared to 3.61 to 3.67 MJ/m3 for the experimental results. The model qualitatively predicted tar content in the producer gas at varying conditions. However, accurate quantification of tar generation in TLUD gasification was not achieved.

Optimising well orientation in hydraulic fracturing of naturally fractured shale gas formations

Complex interactions between hydraulic fractures and natural fractures often result in highly complex fracture networks that might lead to bypassed resources damaging the economic viability of developments. In this study the impact of natural fractures of the formation on production from hydraulically fractured wells is studied using a recently developed fracture upscaling method (FUM). By capturing the distribution of complex fracture networks using FUM, a novel idea of changing the well orientation to optimise recovery is proposed. It is shown that with a natural fracture spacing of 15 m a small change in well orientation up to 30° from the standard orientation can increase the recovery by up to 15% for natural fractures at an angle of at least 60° with σhmax. The increased recovery is a result of the natural fractures and stress orientation complementing each other to assist the propagation of hydraulic fractures deeper into the formation. It is also shown that as natural fracture density increases (fracture spacing decreases) the effect of changing the well orientation becomes more significant. Changing the well orientation when there are two perpendicular planes of natural fractures is also investigated. However, no optimal orientation can be found in these cases, suggesting there needs to be a strong average directionality of the natural fractures in the reservoir to support a beneficial well orientation change. A simple economic analysis shows a small well orientation change can allow a larger well spacing which could lead to a direct reduction in the cost of developing a shale reservoir. The results also show the positive effect this has on the NPV of the project with different gas prices, and a rapid positive NPV status reducing the risk of investment.

Practical interpretation of pressure tests of hydraulically fractured vertical wells with finite-conductivity in naturally fractured oil and gas formations

This paper presents a well test interpretation methodology using characteristic points and lines found on the pressure and pressure derivative versus time log–log plot for the characterization of a finite-conductivity fractured vertical hydrocarbon well in a double-porosity (heterogeneous) formation considering a new and practical analytical Laplacian model which require less computational time and have more accuracy than semi-analytical models. Some existing equations are found to work well for the new model, and new expressions are developed. The accuracy of the developed equations is successfully tested with synthetical examples.

Permeability model for shale and ultra-tight gas formations: Critical insights into the impact of dynamic adsorption

Gas transport in ultra-tight rock is non-Darcian. In addition to continuum flow, there are multiple other flow mechanisms such as slip flow and pore and surface diffusion. Various multi-physics models have been put forth in the literature to forecast the apparent permeability of gas in shales and ultra-tight formations. However, a means of accurately describing the relative contributions of physics in multiscale pore systems remains a challenge. Moreover, it is important to explain pore size, pressure dependency, and the relationships among adsorption, diffusion, and permeability in porous media. For these reasons, a semi-analytical model is proposed to predict gas permeability according to the viscous flux, pore diffusion and surface diffusion and establish control of the adsorbed gas layer. The reliability of the equations developed was checked by validation using experimental and molecular simulation data obtained from macropore- and micropore-sized nanotubes systems respectively. Furthermore, the equations’ performance for micropores was compared to existing theoretical shale permeability models. The subsequent sensitivity analysis showed that permeability is sensitive to the nanoscale geometry factor and adsorption mechanisms. Moreover, the relevance of the surface diffusion was found to increase as the pore size decreased. For instance, surface diffusion constituted over 50% of the apparent permeability below the 10 MPa and 5.0 MPa conditions in micro- and mesopore systems, respectively, while the Darcy scale phenomenon controlled the transport of gas in macropores. Across all diffusion regimes, the microstructure geometry and sorption dynamics significantly influenced the total diffusion of methane, particularly at low pressures and decreased pore sizes. The decline in reservoir pressure during production shifted the relative importance of the adsorption and diffusion mechanisms, consequently altering the apparent gas permeability. Therefore, reservoir management teams should take into account the dynamics of gas permeability at different pressures and representative pore sizes throughout the life cycle of the asset.

High-pressure methane adsorption behavior on deep shales: Experiments and modeling

Understanding methane adsorption behavior on deep shales is crucial for estimating the original gas in place and enhancing gas recovery in deep shale gas formations. In this study, the methane adsorption on deep shales within the lower Silurian Longmaxi formation from the Sichuan Basin, South China was conducted at pressures up to 50 MPa. The effects of total organic carbon (TOC), temperatures, clay minerals, and moisture content on the adsorption capacity were discussed. The results indicated that the methane excess adsorption on deep shales increased, then reached its peak, and finally decreased with the pressure. The excess adsorption data were fitted using the adsorption models, and it was found that the Dubinin–Radushkevich (D–R) model was superior to other models in predicting the methane adsorption behavior. The methane adsorption capacities exhibited strong positive correlations with the TOC content and negative relationships with clay minerals. The methane excess adsorption decreased with the temperature, while the opposite trend would occur once it exceeded some pressure. The presence of the moisture content on deep shales sharply decreased the methane adsorption capacities, and the reduction of the adsorption capacity decreased with the pressure. The moisture would occupy the adsorption sites in the shale pores, which could result in the methane adsorption capacity that decreased.

An alternative method for sourceless density measurement with boron sleeve gamma detectors

Neutron gamma density measurement using dual gamma detectors (NGD-GD) is a popular density measurement method. Compared with other NGD methods, the NGD-GD method has many advantages in tool optimization, cost control, and density precision; however, it is easily affected by the salinity of formation water. To improve the NGD-GD method, the influence mechanism of formation water salinity was discussed, and a feasible improvement scheme using characteristic gamma information was proposed. A special boron sleeve gamma detector was designed to record the capture gamma rays from the boron-10 element. By analyzing the gamma spectrum, pure boron-10 gamma information was extracted from the total capture gamma spectrum for density calculation. Finally, a new NGD method with boron sleeve gamma detectors (NGD-BD) was developed. Results depict that although the NGD-BD method has a slight decrease in density accuracy and precision compared with the NGD-GD method, its performance is significantly improved in high-brine formations, and oil and gas formations. In addition, the NGD-BD method exhibits better performance in terms of density accuracy, density precision, and environmental impact than another NGD method that uses hydrogen capture gamma information. Moreover, the NGD-BD method is easily implemented with low cost and has little impact on existing NGD tools, and hence, it can coexist with other NGD methods to improve logging quality. Overall, the NGD-BD method is a very promising alternative to the NGD-GD method.

The evolution of intra- and inter-molecular isotope equilibria in natural gases with thermal maturation

Naturally occurring hydrocarbon fluids in sedimentary basins have economic, geological and environmental significance. Connecting sedimentary basin temperature-time evolution with petroleum generation and transformation is a long-studied problem. In this study, we investigate the use of a novel tool – multiply substituted isotopologues of methane, for distinguishing between different chemical mechanisms in catagenesis and for characterizing the extent of thermal maturation of thermogenic natural gases. We analyze the stable isotope compositions of a suite of thermogenic gas samples that are globally distributed and cover a wide range in composition and thermal maturation, from dominantly unconventional shale gas formations and a few conventional gas plays. Our data show that methane generated at early thermal maturity has a stable isotope composition governed by chemical kinetics, characterized by a pronounced deficit in Δ12CH2D2; this signature can be explained by its formation chemistry that combines a more D-rich methyl radical pool and more D-poor H radical pool. Methane from higher thermal maturity fluids increases in Δ12CH2D2, reaching equilibrium at vitrinite reflectance maturity (Ro) of approximately 1.5% (equivalent to 170–210 °C peak burial temperature) and higher, which is interpreted to be the result of isotope exchange erasing the disequilibrium signature of catagenetic chemistry, mediated by CH activation during either radical chain reactions or organic-inorganic interactions on mineral surfaces. We further examined hydrogen isotope fractionations among methane, ethane and propane for a compiled global dataset and found that the intermolecular fractionation exhibits a trend similar to that seen for the Δ12CH2D2 value of methane, departing from equilibrium at low thermal maturities and moving towards equilibrium as maturity increases. These findings indicate that the inter- and intra-molecular hydrogen isotope structures of components of thermogenic natural gas transition from chemical-kinetic control at low thermal maturities toward thermodynamic control at higher thermal maturities, mediated by hydrogen exchange reactions. We propose that these systematic relationships could be used to identify the exact thermal maturation stages for natural gases and their associated fluids, especially for oil-associated gas at early maturation.

Development of a Simpler but Accurate Free Gas Deviation Factor for Fractured (Dual-Porosity) Volumetric Gas Reservoir Fluid

Gas compressibility factor, also known as gas deviation factor or Z-factor, is a thermodynamic correction factor which describes the deviation of a real gas from ideal gas behaviour. The, free gas Z-factor in the Material Balance Equation (MBE) of single-porosity gas reservoirs with insignificant rock (matrix) compaction (after pressure depletion) does not reflect cases in low-permeability gas reservoirs having remarkable rock compaction. Through gas MBE modifications, previous researchers developed Z-factors for dual-porosity (fractured) low permeability gas reservoirs by incorporating gas desorption; however, their approaches create complexity for routine calculations. Therefore this study was designed with the purpose of deriving a free gas Z-factor for single-porosity low-permeability gas reservoirs and further modifying it for more simplicity and accuracy in a dual-porosity scenario. The free gas Z-factor derived for single-porosity low-permeability gas reservoirs is expressed as: where , , , , and are single-porosity Z-factor without rock compaction at pressure , water compressibility, initial water saturation, matrix compressibility, initial gas saturation and pressure depletion, respectively. However, the developed dual porosity free gas Z-factor model incorporates ratio of dual porosity to initial matrix porosity, and it is expressed as: where and are initial matrix porosity and fracture porosity, respectively. The Z-factor model was graphically and statistically correlated with an existing free gas Z-factor model for dual porosity reservoirs. For all the hydraulically fractured shale gas formations considered, the correlations yield R2 values of 1.000.

Hydraulic Fracturing Tight Reservoirs: Rock Mechanics and Transport Phenomena

Conventional reservoirs have been fracture stimulated using acid fracturing and proppant fracturing.Acid fracturing is performed to improve well productivity in acid-soluble formations such aslimestone, dolomite, and chalk. Hydrochloric acid is generally used to create an etched fracture,which is the main mechanism for maintaining the fracture open during the life of a well. Proppantfracturing is an alternative option that has been applied in carbonaceous and siliceous formations.There is no quantitative method to provide an answer of whether acid fracturing or proppantfracturing is an appropriate stimulation method for a given carbonate formation. How rockmechanics can be applied to decide on what method is more effective? Laboratory experiments havebeen performed to simulate acid etched to study the effect of elastic, plastic and viscoelastic rockbehavior and their effects on fracture conductivity. Comparison of acid vs. proppant fracturingconductivity in carbonate formation is presented.Fracturing low permeability reservoirs is totally different than fracturing tight formations. Thefracture geometry required in low permeability reservoirs need to be planar, conductive andpenetrating deep in the reservoir. Fracture complexity in these reservoirs is to be avoided foroptimum stimulation treatment. However, in fracturing tight formation, a complex fracture networkis desirable for better recovery. Creating multiple fractures in horizontal wells without the use ofmechanical intervention, is becoming essential especially in tight gas reservoirs. We have learnedhow to initiate hydraulic fractures into a specific direction and place as many fractures as desired inhorizontal wells but with casing and perforation. The challenge now is to initiate weak point acrossthe horizontal well such that fracturing fluid will initiate a fracture there. How rock mechanics hasbeen applied to achieve this objective? We are fracturing tight gas sand in harsh environment, atdepth more than 18000 ft, of temperature close to 400 °F, and one can figure out the extreme in-situstresses relevant to this depth.When the reservoir pressure decreases, the elastic displacement in response to the increase ineffective stress will cause natural fractures to close leading to a decline in reservoir productivity.
 The matrix medium feeds the natural tensile fractures which carry the fluids to the wellbore. Thedecline in conductivity with increasing effective stress should follow a logical declining rate tosupport a given production rate. How the concept of effective stress has been applied to understandthe stress-dependent conductivity of various conductive components of a given reservoir? Rockmechanics testing of these stress sensitive reservoirs becomes vital to optimize fracturing tightformations.Economical production from tight reservoirs, including shale gas and shale oil formations, requireshorizontal well drilling and massive proppant hydraulic fracturing stimulation. The stimulationinvolves generating sufficient fractures network or stimulated reservoir volume (SRV), which isachieved by placing optimized stimulation treatments along the horizontal section of wellboresideally drilled from multi-well pads to increase the production rate and ultimate recovery. Hydraulicfracturing in naturally fractured formations is characterized by generating a fractures’ network thatshould be designed for in extremely low permeability of unconventional reservoirs. Fractures shouldextensively reach shale matrix to achieve commercial gas production. Therefore, production rate andultimate recovery depend on the size of the created SRV.The transport phenomena controlling fluid flow through tight formation is no longer sufficient to bemodeled by Darcy’s flow. Diffusion and imbibition are important transport mechanisms. The conceptof osmosis and flow through a semi-permeable membrane component are critical. Additionally,diffusion and a special case of molecular flow due to Knudson effect will be discussed. Conventionalreservoir simulation collapses when trying to simulate fluid flow through tight reservoirs. Numericalstudies on a hydraulically fractured well to simulate the dynamic processes during fracturinginjection, following well shut-in (soaking), and production are discussed.