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The growth habit of natural gas hydrate in formation pores directly influences its occurrence and distribution, which are fundamental factors for macroscopic reservoir properties. In order to simulate the hydrate growth at pore scale and demonstrate the growth process directly, microscopic visualization experiments were carried out using glass etching model and high-resolution video microscope in this work. The crystal growth behavior of methane hydrate was observed clearly in real time, and fluid state and system pressure were analyzed. On this basis, hydrate growth patterns and corresponding control mechanisms were investigated. The results show that for a static methane–water system, the hydrate crystal grew rapidly about 10 min after perturbation. The solution gas crystallized with water, forming colorless, transparent and polygonal crystal with sharp edge and smooth surface. The free gas crystallized with water at the gas–water interface first, resulting in a quick formation of hydrate crust. Then water passed through the hydrate crust slowly and crystallized with the free gas trapped inside hydrate crust. The resulting hydrates seemed to rough and honeycomb aggregations of tiny and tightly packed crystal particles. The two kinds of hydrate with different morphologies represent two typical hydrate growth patterns. For the hydrate growth pattern of solution gas–water, solution gas, which migrates to the crystal growth front driven by the concentration gradient, is in direct contact with water, leading to a fast crystal growth rate. For the crystal growth pattern of free gas–water, the preferentially formed hydrate crust at the gas–water interface not only separates the free gas from the water phase, but also selectively obstructs the passage of gas and only allows water to pass slowly, which slows down the hydrate growth process. This research is helpful to further understand the experimental phenomena at the core and field scale, explain the existing problems, and provide support for the research on the dissociation and exploitation of natural gas hydrate.

Natural gas hydrate is generally disseminated in tilted sediments. The inclination of hydrate reservoirs significantly affects the fluid migration behaviour and production potential. However, most of the current simulations ideally assume that the hydrate reservoir is horizontally distributed; resulting in the effect of the formation dip on the well deployment and corresponding gas production remains unclear. Here, we implement a real inclined alternating sand–clay hydrate reservoir model based on geological data from the Nankai Trough, Japan, to simulate the production performance of a single horizontal well and dual horizontal wells. Results show that the gas and water productions are enhanced when a single horizontal production well is deployed in the structural low of the reservoir. The gas and water production performance in upper sandy reservoir and the water extraction in the middle muddy reservoir are sensitive to the layout of the production wells, which can cause the daily difference is over 6%. The gas-to-water ratio is independent from the structural deployment positions of the horizontal wells in the same inclined layer. Compared to the single depressurization method, placing a horizontal thermal injection well in the structural high of the upper inclined sandy reservoir and a horizontal production well in the structural low of the same formation improves the gas recovery efficiency nearly twice, which is recommended for production enhancement. Our findings are useful for achieving effective and economic gas recovery from natural inclined layered hydrate reservoirs.

Class 1 hydrate reservoirs are regarded as the most promising targets for gas production. Previous investigations in the northern South China Sea have proven that the low‐permeability hydrate reservoir at site GMGS3‐W19 is a Class 1 hydrate deposit. However, the dynamic production behaviors of this type of reservoir are not yet fully understood. Here, we report gas recovery from hydrate reservoirs containing underlying free gas layers with different initial gas saturations and investigate the effects of absolute permeability and depressurization pressure on gas production performance. The results show that high initial gas saturation of the underlying free gas layer and low bottom‐hole pressure are advantageous for enhancing the gas production performance. The effects of absolute anisotropic permeability and isotropic permeability on gas recovery from Class 1 hydrate reservoirs are different. For long‐term gas production from this hydrate reservoir with any initial gas saturation, a higher horizontal permeability (permeability anisotropy more than 10) in the hydrate layer is remarkably beneficial to stimulate gas extraction and decrease the amount of produced water replenished by inflows from permeable overlying and underlying sediments. Moreover, the gas production rate is highly consistent with the hydrate dissociation ratio, one of the main factors affecting the gas production performance, in Class 1 hydrate reservoirs with different permeabilities. However, for this type of hydrate reservoir with permeability anisotropy larger than 5, the larger the horizontal permeability in the hydrate layer can form more secondary hydrates. The increment in secondary hydrate formation negatively influences the hydrate dissociation ratio and gas recovery. Thus, it is also significant to weigh the permeability anisotropy of the hydrate layer and the secondary hydrate formation amount during the production progress. These findings can contribute to estimating the gas recovery efficiency in Class 1 hydrate reservoirs and optimizing the production process in similar areas.

The key to realize the commercial production of natural gas hydrate (NGH) is to increase theNGH productivity significantly in the scale of magnitude. Whether NGH production can be commercialized depends on two aspects. The first is whether the in-situ recoverable reserves are large enough to support the basic production period for commercial production. The second is whether the average productivity can reach the standard for commercial production. In this paper, we will analyze mainly about the potential stimulation technologies for NGH development, and discuss about the basic principles, the evaluation methods, and the technical bottlenecks for NGH production and stimulation. The results indicate that the main mechanisms for increasing theNGH productivity are in three respects, namely enlarging the drainage area, increasing the NGH dissociation efficiency, and improving the seepage conditions. With complex-structure wells and multiple-well patterns, combined with novel production methods and/or reservoir stimulation technologies, the NGH productivity can be increased greatly. Particularly, the complex-structure wells and well patterns are very important for increasing NGH productivity. With complex-structure wells and well patterns, combined with heat injection and/or reservoir stimulation, NGH productivity can be increased on a magnitude scale. Currently, in fundamental researches, there are some technical bottlenecks for the studies of NGH production, mainly in sample preparation, simulated reservoir monitoring, and mechanical coupling technologies. Therefore, it is suggested that the study focuses should be on the above technical bottlenecks during the basic research on how to increase the NGH productivity. It is concluded that the combined application of complex-structure wells (horizontal wells and multi-lateral wells), well-pattern production models (with multi-cluster/group well production), the novel production methods (mainly thermal stimulation, together with depressurization), and reservoir stimulation technologies (hydraulic fracturing) are the keys to increase NGH productivity in the scale of magnitude.

Gas production from hydrates induced by depressurization is a complex thermal-hydrodynamic-mechanical–chemical (THMC) coupled process. In this paper, we present a THMC coupled model to simulate the fluid flow in hydrate-bearing sediments (HBS) and the geomechanical behavior of HBS. The model is made of two subsystems, which are the fluid part of non-isothermal multi-phase flow with hydrate kinetic and solid part of geomechanical deformation. It accounts for two-way coupling effects between these two subsystems, i.e. the effect of pore pressure and hydrate dissociation on the solid mechanical behavior and the effect of stress on the hydraulic behavior. A new numerical method based on the hybrid control volume finite element method (CVFEM)-finite element method (FEM) is developed to solve the mathematical models. The local conservative CVFEM is used for the fluid part, and the standard FEM for the solid part. In the framework of hybrid CVFEM-FEM, the local conservation is reserved and the primary variables for the two subsystem are co-located. A multi-point flux approximation (MPFA) is adopted without orthogonal meshes so that it is very flexible to build complex geometrical models. The accuracy and reliability of the newly developed simulator QIMGHyd-THMC are tested by comparing with two experimental examples and a large-scale benchmark problem of other popular simulators.

The permeability anisotropy (ie, horizontal, kr, to vertical, kz, permeability ratio) of gas hydrate reservoirs may be a significant factor that affects hydrate dissociation and gas production. Here, site SH2, a candidate for field testing comprising a clayey silt gas hydrate reservoir in the Shenhu area in the South China Sea, was chosen to investigate the effect of permeability anisotropy on gas production behavior through numerical simulations. The spatial distribution of physical fields (ie, pressure, temperature, and saturation) and the evolution of gas and water recovery are comparatively analyzed. The simulation results show that permeability anisotropy has a significant impact on gas extraction, especially when the horizontal permeability is higher than the vertical one. The sensitivity analyses indicate that permeability anisotropy in both medium‐permeability (10‐100 mD) and low‐permeability (1‐10 mD) sediments are conducive to hydrate dissociation and that a higher horizontal permeability is more favorable for gas production. Comparatively, permeability anisotropy in low‐permeability sediments is not beneficial for improving production efficiency. In addition, our work also suggests that heterogeneous hydrate saturation in a reservoir‐scale model should be employed in future predictions because the gas production potential will be overestimated in a homogeneous reservoir under the same conditions. These findings contribute to a clear understanding of the influence of reservoir properties on gas hydrate dissociation processes and provide a reference for future field trials and commercial production.

The reaction surface area of hydrate (RSAH) inherently controls the reaction rate of hydrate dissociation in the pore spaces, which further affects the gas production behaviour of the hydrate-bearing sediments. The objective of this work is to measure and describe the RSAH evolution during MH dissociation and analyse its implications for gas production. The CT images obtained from different dissociation stages showed the RSAH decreased slowly in the early stage of dissociation and rapidly in the later stage. By considering the pore structure features of sediment, a fractal method was proposed to predict the relationship between RSAH and hydrate saturation, which showed better agreement with the CT experimental results than that of Yousif's model. Further hydrate production numerical simulations embedded with different RSAH predictions indicated that the hydrate production process was significantly influenced by the variations in RSAH. The simulated gas production rate based on the fractal model was lower than that of Yousif's model, the far-field pressure drop in the fractal model was slower, and the advance of the dissociation front and the transfer of the pressure field in Yousif's model was faster than that of the fractal model. Highlights • The changes in hydrate reaction surface area during hydrate dissociation are experimentally measured and analysed. • A fractal model considering the pore structure characteristics of porous media is proposed and experimentally validated. • A comparison of the hydrate dissociation rate predicted by the proposed fractal model and by Yousif’s model is made. • Implications of reaction surface evolution during the hydrate dissociation for hydrate productions are modeled.

ontact area are two main ways to raise the productivity of hydrate. An exploitation technique based on large borehole with multi-lateral branches (LB & MB) was proposed in this paper. This technique is mainly intended for the clayey silt hydrate reservoir in the South China Sea, and its main purpose is to alleviate the sand output from formation for maintaining the stability of the reservoir and to greatly increase the gas productivity of the reservoir. In this paper, the following aspects were mainly expounded: definition of the basic geometric parameters for layout of multi-lateral branches in clayey silt hydrate reservoir, simulation of the stimulation effect of a typical well profile with two branches, and prediction and simulation of the reservoir failure risk in a well profile with eight branches. The results show that the LB & MB effectively improves the flow field in the formation, raises the productivity of the reservoir and may also help to decrease the produced water-gas ratio (WGR). When the lateral branches spacing is too small, the failure zones around adjacent lateral branches overlap each other, possibly causing reservoir failure in a larger range. Therefore, the geometric parameters of multi-lateral branches depend on the dual control of the productivity and geotechnical risk factor of reservoir. Further study is being carried out, so as to obtain the optimal combination of parameters of multi-lateral branches.

The characteristics of drilling fluid invasion into hydrate-bearing sediments (HBS) would trigger geological risks. However, invasion mechanisms and formation responses during drilling the gas hydrate reservoirs, still remain poorly understood. Thus, we develop a three-dimensional (3-D) numerical model to investigate the invasion process in drilling hydrate with and without hydrate dissociation. This model model deals with the changes of pressure and temperature induced hydrate dissociation in near-wellbore region and subsequent influence on the process of drilling fluid invasion. The results indicate that the invasion of drilling fluid induces changes in pressure and temperature fields, with a gradual decrease from wellbore to the formation. The cumulative filter volume increases while the invasion velocity decreases gradually over invasion time. Besides, the increase of temperature and decrease in drilling fluid pressure can promote the dissociation of hydrate. Moreover, characteristics and mechanisms of drilling fluid invasion into hydrate reservoirs are analyzed based on the numerical results. The optimization strategies and drilling technology are discussed to prevent hydrate dissociation and control geological risks during drilling hydrate.

Strong static electric fields can accelerate hydrate decomposition in pure water and induce the migration of ions (Na+ and Cl-) in salty water. The impact of Na+ and Cl- migration on hydrate decomposition under static electric fields deserve to be evaluated. Toward this goal, molecular dynamics (MD) simulations were conducted to investigate the effects of the migration of Na+ and Cl- induced by static electric fields on the decomposition behavior of methane hydrate. We find that the hydrate cages can be pierced and destroyed by the migration of Na+ and Cl- under static electric fields at least 0.9 V/nm at our conditions, thus causing hydrate decomposition. With increasing static electric field strength, the destructive ability of ions to hydrate becomes stronger and hydrate decomposition becomes faster. Moreover, detailed analysis shows that Na+ and Cl- can penetrate and pass through the hydrate block, and some ions concentrate on the surface of the hydrate block and cause hydrate decomposition. This work provides a new method for natural gas hydrate extraction and inhibition of hydrate formation in gas-oil pipelines. The hydrate is worth examining as a new ion exchange membrane material in the future due to the difference of ions migration velocity in hydrate.

Reservoir stability is a key factor in the production of natural gas hydrate (NGH), and also a prerequisite to ensuring safe and efficient NGH production. However, it has been rarely discussed. To analyze the reservoir stability in the process of NGH production by depressurization in the Shenhu area of the South China Sea, we established a 3D geological model of NGH production by depressurization on the basis of NGH drilling data in this area, which was then discretized by means of nonstructural grid. Then, the mathematical model coupling four fields (i.e. thermal, hydraulic, solid and chemical) was established considering the heat and mass transfer process and sediment transformation process during NGH production. The model was solved by the finite element method together with the nonstructural grid technology, and thus the time-space evolution characteristics of reservoir pore pressure, temperature, NGH saturation and stress in the condition of NGH production by depressurization were determined. Finally, reservoir subsidence, stress distribution and stability in the process of NGH production by depressurization in the Shenhu area were analyzed. The results obtained are as follows. First, the higher the reservoir permeability and the larger the bottomhole pressure drop amplitude are, the larger the subsidence amount and the higher the subsiding speed. Second, as the reservoir pore pressure decreases in the process of production, the effective stress increases and the shear stress near the well increases obviously, resulting in shear damage easily. Third, the increase of effective reservoir stress leads to reservoir subsidence, which mainly occurs in the early stage of NGH production. After the production for 60 days, the maximum reservoir subsidence reached 32 mm and the maximum subsidence of seabed surface was 14 mm. In conclusion, the NGH reservoirs in the Shenhu area of the South China Sea are of low permeability and the effect range of reservoir pressure drop is limited, so the reservoirs would not suffer from shear damage in the sixty-day-production period. Keywords: South China sea, Shenhu area, Natural gas hydrate (NGH), Natural gas hydrate production by depressurization, Effective stress, Reservoir stability, Multi-field coupling numerical simulation

The caved carbonate reservoir is a special and complex reservoir with different size cavities, which implies a strong heterogeneity. It is a big challenge to characterize such reservoirs. The dual-porosity model and radial composite model are the two most commonly used models for the interpretation of well test in caved carbonate reservoirs. However, more studies are needed to determine whether these models can be applied to this special and complex type of reservoir. In this paper, first we classify the log-log plots of test pressure into four types and analyze the characteristics of each type. The results show that the cavity controls the pressure response and that the above-mentioned models are not appropriate for the well test interpretation of caved carbonate reservoirs. We also developed a numerical well test model for caved carbonate reservoirs. The model includes two cases: a well drilled outside a cavity and a well drilled inside a cavity. The model's equations were solved by the finite-element method. We analyzed the pressure response of the developed model and found that the log-log plots for the model of a well outside a cavity are similar to that of the dual-porosity model, but the physical mechanisms of these two models are different. The model of a well inside a cavity is similar to the radial composite model except for a deviation in the distance of the well from the center of the cavity. Sensitivity studies show the size of the cavity, its permeability, and the distance from the well to the cavity are the main factors influencing the pressure response behavior. Two field examples of build-up pressure tests are provided to show how the proposed model can be used to understand the properties of caved carbonate reservoirs and characterize them.

Natural gas hydrate is prevalent in ultralow-permeability fine-grained sediments with substantial reserves. However, effective and safe gas production from fine-grained hydrate reservoirs remains a global challenge. Here, a multilateral horizontal well system is innovatively employed to improve production efficiency in fine-grained hydrate reservoirs. A three-dimensional (3D) numerical model of a real gas hydrate reservoir is constructed, and the influences of well configuration, deployment location, depressurization pressure, and reservoir properties on production are systemically and quantitatively evaluated. The spatial distributions of the physical properties of the 3D reservoirs during gas production are clearly revealed. The results indicate that the production efficiency of multilateral horizontal wells improves with increasing branch number and length, particularly when the ratio of branch length to reservoir width exceeds 0.15. Branch interference and perforation length positively affect production enhancement when multilateral horizontal wells are deployed in hydrate reservoirs with specific ultralow permeabilities; these discoveries are revealed for the first time. Multilateral horizontal wells with helically and vertically distributed equal-length branches yield high production efficiencies, and their optimal locations are in the lower sections of the reservoirs, particularly within high-isotropic-permeability reservoirs. Moreover, uniformly low depressurization pressure in helically distributed branches facilitates gas extraction; gas recovery efficiency increases by 8% when production pressure decreases by 1 MPa. This study suggests that the use of a helical multilateral well system is a promising strategy for achieving commercial gas production from fine-grained hydrate reservoirs.

Ilk et al.’s deconvolution algorithm using B-splines involves the Laplace transformation of the convolution equation with respect to production rate and wellbore pressure based on Duhamel principle. However, for common cases, the production rate function has “discontinuity” with respect to production time; it does not satisfy the precondition that the function to be transformed by Laplace transformation should be continuous. This inherent defect may directly cause enormous amount of computational time or even the failure of the numerical Laplace inversion in the deconvolution process. Based on these concerns, a fundamentally improved deconvolution algorithm using B-splines is presented here. In the convolution equation, the wellbore pressure derivative corresponding to constant unit production rate as the target of deconvolution is still represented by weighted summation of second-order B-splines; however, the computation process of the deconvolution is kept in the level of integral in the real time space instead of the Laplace space, for the reason that there will be no continuity requirement for the production rate function in the application of Duhamel principle for the deconvolution computation problem. According to the real production rate history, a technique of piecewise analytical integration is adopted for obtaining the elements of sensitivity matrix of a linear system with respect to weight coefficients; the linear system is generated by substituting the measured wellbore pressure data and corresponding variable production rate data into the convolution equation containing B-splines. The proposed direct analytical solution method of the integration for calculating the elements of the sensitivity matrix can not only guarantee the success of the deconvolution computation, but also can largely enhance the deconvolution computation speed. Moreover, in order to further improve the computation speed, a binary search method is also applied to find which production segments (with constant production rate) the measured wellbore pressure data points locate at in the deconvolution computation process. Another linear system with respect to weight coefficients for the regularization from Ilk et al.’s deconvolution algorithm is appended in order to overcome the effect of data errors. The two linear systems are combined together as an over-determined linear system, which can be solved by the least square method. Eventually, the reconstructed wellbore pressure and its derivative by B-splines corresponding to the constant unit production rate can be obtained. Numerical experimental tests demonstrate that the improved deconvolution algorithm exhibits good accuracy, computation speed and stability of data error tolerance. And the statement on how to perform the regularization when data error exists is also made in order to deconvolve the correct wellbore pressure derivative. The improved deconvolution algorithm is also applied into an actual field example. It is found that the deconvolution results by the improved deconvolution algorithm have good agreement with the ones by Von Schroeter et al.’s deconvolution algorithm and by Levitan et al.’s deconvolution algorithm as a whole; and the feature of typical log-log curves of the wellbore pressure drop and the wellbore pressure derivative corresponding to the improved algorithm is very close to the one of typical log-log curves calculated directly from the wellbore pressure data in the well shut-in period. In addition, through many numerical experimental tests, it is also concluded that as the quantity of data largely increases, the improved Ilk et al.'s deconvolution algorithm exhibits the big advantage in fast computational speed over von Schroeter et al.’s algorithm and Levitan et al.’s algorithm.

The elastic wave velocities of hydrate-bearing sediments (HBS) are considerably affected by the content of free gas and hydrate. Although several existing models relate the free gas and hydrate saturation to acoustic velocities, the accuracy of these models is still uncertain because of the difficulty in determining the gas content. In this study, we acquired the gas volume fraction and acoustic velocity data of the hydrate-bearing sands through a X-ray computed micro-tomography (CT) and an ultrasonic apparatus, respectively. The acoustic velocities increase slowly at low hydrate saturation (Sh

A new well test model for a vertical fractured well is developed based on a discrete-fracture model in which the fractures are discretized as one dimensional (1-D) entities. The model overcomes the weakness of complex meshing, a large number of grids, and instability in conventional stripe-fracture models. Then, the discrete-fracture model is implemented using a hybrid element finite-element method. Triangular elements are used for matrix and line elements for the fractures. The finite element formulation is validated by comparing with the semi-analytical solution of a single vertical fractured well. The accuracy of the approach is shown through several examples with different fracture apertures, fracture conductivity, and fracture amount. Results from the discrete-fracture model agree reasonably well with the stripe-fracture model and the analytic solutions. The advantages of the discrete-fracture model are presented in mesh generation, computational improvement, and abilities to handle complex fractures like wedge-shaped fractures and fractures with branches. Analytical results show that the number of grids in the discrete-fracture model is 10 % less than stripe-fracture model, and computational efficiency increases by about 50 %. The more fractures there are, the more the computational efficiency increases.

Based on the characteristics of fractures in naturally fractured reservoir and a discrete-fracture model, a fracture network numerical well test model is developed. Bottom hole pressure response curves and the pressure field are obtained by solving the model equations with the finite-element method. By analyzing bottom hole pressure curves and the fluid flow in the pressure field, seven flow stages can be recognized on the curves. An upscaling method is developed to compare with the dual-porosity model (DPM). The comparisons results show that the DPM overestimates the inter-porosity coefficient lambda and the storage factor omega. The analysis results show that fracture conductivity plays a leading role in the fluid flow. Matrix permeability influences the beginning time of flow from the matrix to fractures. Fractures density is another important parameter controlling the flow. The fracture linear flow is hidden under the large fracture density. The pressure propagation is slower in the direction of larger fracture density.

The coalbed methane (CBM) desorption area is highly important in the placement of wells to produce an adequate working system. This paper develops a homogeneous seepage model of CBM that incorporates desorption and uses a finite-element method to obtain the pressure field in complex boundary cases influenced by adjacent wells. The pressure field is presented in a 2D and pseudo-3D form that visually demonstrates the shape of the pressure profile and the pressure expansion. A method of combined numerical computation and contour drawing technology is used to determine the CBM desorption area and pressure drop region. By analyzing the main factors that affect the CBM desorption region, we demonstrate that a higher value of critical desorption pressure yields a larger desorption area of the seam. The effect of the permeability is different from the value of the critical desorption. This effect is determined by the critical desorption pressure level and the intersection of pressure profiles with different permeabilities. Permeability anisotropy leads to a desorption area with an elliptical shape. We also demonstrate that a greater flux of methane will result in a greater desorption region, and the effects of the distance between wells and the desorption area are closely related to the permeability. The developed model is applied in a field case to predict the desorption area. (C) 2015 Elsevier B.V. All rights reserved.

The field production test of gas hydrate conducted in South China Sea has been proven to be successful, but the production still cannot satisfy the requirement for commercial production. In order to achieve a higher production efficiency, the numerical simulation code Tough + Hydrate was employed to estimate the detailed production potential of four typical coring sites XX01∼XX04 in Shenhu area, which have distinct reservoir conditions and are considered as the focus for production tests. Our simulation results show that the hydrate deposit at Site XX03 featured with the highest permeability has the most promising gas production, despite the least thickness 11.56 m of the hydrate-bearing layer. In addition, we have also investigated the impact of the controllable engineering facts on the production, which suggests that the lower depressurization pressure and longer perforated interval would contribute to a higher gas production. And when the lower water production is considered, the bottom half perforated interval would be a relatively more promising design for the production. This research gives a forward sight for production prediction and our findings may provide a theoretical guideline in selection and design of the production targets.

Caved carbonate reservoirs are very special because of the strong heterogeneity. The pressure transient behavior of the caved carbonate reservoirs is quite different from the conventional homogeneous or dual medium reservoirs because of the presence of large-scale cavities. There are two types of cavities: filled and unfilled, which dominated the production of the reservoirs. Fluid flow in the unfilled cavity should be described by Stokes' equation rather than Darcy's law. It is needed to better understand the role of the unfilled cavities plays in the pressure transient analysis. The objective of this work is to analyze the pressure transient behavior of the unfilled cavities. A coupled Stokes-Darcy pressure transient model is developed and the finite element method is applied in the solutions of the mathematical models. Then, the numerical pressure transient model is used in the analysis of two typical cases: a well drilled into the unfilled cavity (WIC) and a well not drilled into the unfilled cavity (WOC). The type curves of the WIC model indicate that flow in the unfilled cavity is an oscillated pressure-drop rather than a radial flow. The unfilled cavity that the well drilled into would be considered as an enlarged wellbore which is equivalent to a negative skin factor, as a consequence the wellbore storage coefficient will increase. Main characteristics of type curves for WOC model are the valley on the pressure derivative. A cavity with a larger size and smaller distance from the wellbore would give rise to a deeper valley. Comparative results indicate that unfilled cavities described by the Stokes' equation are not the limit of the filled cavities with extremely large mobility, which was predicted by previous work.