Dual-porosity Reservoir Research Articles

Dynamic Scaling Prediction Model and Application in Near-Wellbore Formation of Ultradeep Natural Gas Reservoirs

Summary To address the significant scaling challenges within the near-wellbore formation of ultradeep natural gas reservoirs characterized by high temperature and high salinity, we developed a dynamic scaling prediction model. This model is specifically designed for the prediction of scaling in gas-water two-phase seepage within fractured-matrix dual-porosity reservoirs. It accounts for the concentration effects resulting from the evaporation of water on formation water ions. Our scaling model is discretely solved using the finite volume method. We also conducted on-site dynamic scaling simulations for gas wells, allowing us to precisely predict the distribution of ion concentrations in the reservoir, as well as changes in porosity and permeability properties, and the scaling law dynamics. The simulation results reveal a significant drop in formation pressure, decreasing from 105 MPa to 76.7 MPa after 7.5 years of production. The near-wellbore formation is particularly affected by severe scaling, mainly attributed to the radial pressure drop funneling effect, leading to a reduction in scaling ion concentrations in the vicinity of the wellbore. Calcium carbonate is identified as the predominant scaling component within the reservoir, while calcium sulfate serves as a secondary contributor, together accounting for roughly 85.2% of the total scaling deposits. In contrast, the scaling impact on the matrix system within the reservoir remains minimal. However, the central fracture system exhibits notable damage, with reductions of 71.2% in porosity and 59.8% in permeability. The fracture system within a 5-m radius around the wellbore is recognized as the primary area of scaling damage in the reservoir. The use of the simulation approach proposed in this study can offer valuable support for analyzing the dynamic scaling patterns in gasfield reservoirs and optimizing scaling mitigation processes.

Well-Testing Model for Dual-Porosity Reservoir considering Stress-Sensitivity and Elastic Outer Boundary Condition

Stress sensitivity and the elastic outer boundary (EOB) condition have a great effect on the analysis of the characteristics of the fluid flow in a reservoir. When researchers analyzed the characteristics of the fluid flow, they have considered the stress sensitivity and the EOB condition separately but have not considered them simultaneously. Therefore, errors are inevitable during the analysis of well testing. The main object of this work is to present a well-testing model for stress-sensitivity dual-porosity reservoir (DPR) with EOB to improve the accuracy of the analysis of well-testing data. To this end, in this paper, we established a well-testing model for the DPR, considering the stress sensitivity and the EOB simultaneously, and presented its semianalytical solution. On the basis of the consideration of the EOB condition and stress sensitivity of permeability (SSP), a seepage model for the DPR with the EOB is built using the continuity equation, motion equation, state equation, and interporosity flow equation between matrix and fracture, which considers the stress sensitivity, wellbore storage, and skin. To solve this model, a nonlinear partial differential equation is changed into a linear form of a partial differential equation by introducing an effective well radius and applying Pedrosa’s transformation and perturbation transformation. Applying the Laplace transformation, an analytical solution in the Laplace space is obtained, and curves of pressure and pressure derivative (PPD) are drawn by numerically inverting them. The model is verified by comparing it with the EOB without consideration of SSP and using case data. The sensitivity of parameters on the curves of PPD is analyzed. This work may be significant for evaluating more accurately the parameters of wells and reservoirs using well testing.

Curvature analysis and its correlation with faults and fractures in presalt carbonates, Santos Basin, Brazil

Presalt lacustrine carbonate reservoirs in the Santos Basin, Brazil, can have a high degree of fracturing. Properly characterizing such properties is important due to their influence on the porosity–permeability system. It may play a key role in the so-called excess permeability features and the flow behaviour, especially in the Aptian Alagoas Stage. Therefore, 3D characterization of the fracture system improves the reservoir model. For this purpose, correctly identifying the fault and fracture zones in seismic data is crucial. This task is generally performed manually and guided by amplitude interpretation or geometric seismic attributes. However, due to the seismic resolution of the pre-salt seismic datasets, many faults and fractured zones are not identified in the seismic amplitude domain or by standard geometric attributes such as coherence. Improving the resolution of seismic data and its geometric attributes can positively impact the delineation of fractured zones, structural lineaments, and their connectivity. Curvature (k) attributes have a high potential to reveal vertical to subvertical subseismic-scale structures, which is the main type of strain generated from the tectonic style in the Pre-salt rocks. Among the curvature attributes, the most-positive (k1) and the most-negative (k2) attributes are some of the most commonly used. The present study evaluates the use of seismic inverse Q-filter and three different dip estimation techniques based on Fast Fourier Transform (FFT), Principal Component Analysis (PCA), and Phase Gradient (PG). It also adds two postfiltering techniques (median and recursive Gaussian filters) to obtain a consistent most-positive curvature. We then analyse two analytical models that correlate the volumetric fracture intensity, measured on Borehole Image Logs (BHI), with the curvature. Then, we perform a comprehensive study to understand the role of seismic-scale strain (translated into curvature) and mechanical stratigraphy in the development of fractures in the presalt, where we address that in addition to seismic-scale deformation, the contents of silica, clay, and organic matter are also relevant variables. These results can help to guide future studies of fracture characterization to prospect naturally fractured reservoirs or to estimate fracture intensity for dual-porosity reservoir modelling on the Santos presalt carbonates.

A novel calculation model, characteristics and applications of Archie's cementation exponent in dual porosity reservoirs with intersecting dual fractures

Fractured rock samples are difficult to use for ground conductive experiments, and there are few related simulation researches of Archie's cementation exponent in the reservoirs with intersecting dual fractures. In order to obtain the cementation index for saturation evaluation when no experiments and methods are available in such reservoirs, we focus on the researches of the cementation exponents in these reservoirs. Based on the Maxwell-Garnett mixing rule and the morphological characteristics of fractures in reservoirs, the method for obtaining the cementation exponents in reservoirs with parallel fractures at any inclination angle are first reviewed. secondly, the rock model of the dual porosity reservoirs with two intersecting fractures is constructed. The rock model is divided into four equal parts through equivalent processing, and the respective cementation exponents of the four parts can be calculated. Based on the series and parallel connection of Ohm's law, a novel calculation model of the overall cementation exponent of the rock model is established. Thirdly, using the novel model, the characteristics of cementation exponent of the rock model affected by different fracture dips, fracture porosities and included angles between the two fractures are calculated. In terms of detail and overall, the trend curves of these characteristics exhibit different nonlinear characteristics. The combined effect of the dip angles of the dual fractures, the included angle between them, the porosities of them and the porosity of matrix makes the cementation exponent characteristics more complex than that of single fracture or parallel fractures. Fourthly, the novel calculation model is used to evaluate the cementation exponent and fluid saturation of the two wells in the Chang 8 Formation in the southwest Ordos Basin, China, and the application results can demonstrate the reliability and availability of the novel model of cementation exponent in the reservoirs with intersecting dual fractures. At last, the application effect, influencing factors and applicable conditions of the novel calculation model of cementation exponent are discussed in detail. These applications and analyses show that it can provide an alternative solution for cementation exponent estimations in such fractured reservoirs, especially when experiments are not available.

Constitutive and numerical modeling for the coupled thermal-hydro-mechanical processes in dual-porosity geothermal reservoir

Enhanced geothermal system (EGS) is viewed as one of the most practical methods to explore geothermal energy in hot dry rock (HDR), which can contribute to zero carbon emissions and provide reliable and renewable energy. Modelling the performance and long-term environmental effects of the EGS remains a challenge as the rock is often fractured and experiences complicated multi-physics coupling behaviour. Despite studies on constitutive or numerical modelling of coupled behaviour in deformable dual-porosity media, those developed models often ignore the fully coupled processes in heat transfer and are highly empirical. Based on a non-equilibrium thermodynamics approach, the Mixture-Coupling Theory, this research derives the fully coupled Thermo-Hydro-Mechanical (THM) governing equations for dual-porosity geothermal reservoirs, addressing the interaction between strain, pore/fracture pressure and temperature. The constitutive model is obtained by the analysis of Helmholtz free energy evolution in dual-porosity reservoirs. The proposed model determines the fully coupled evolution of solid stress, both pore and fracture porosity, and solid entropy density. The governing equations can predict the fully coupled THM effect in dual-porosity geothermal reservoirs. Numerical modelling is then performed to study the production performance and coupled THM response in an EGS. The modelling results show that the production temperature is determined by the coupled THM effects. Porosity change is mainly determined by temperature change (accounting for over 87% of the total porosity change) during the extraction. The porosity change accounts for 1.03% and 1.23% of the initial porosity for pore and fracture, separately.

Well testing of radial jet drilling wells in geothermal reservoirs

Radial Jet Drilling (RJD) is a stimulation technique to increase a well’s performance through creation of multiple laterals of up to 100 m long. The technique has been used in the petroleum industry for several years and recently also for geothermal reservoirs. Interpretation of well tests of a well with multiple laterals may become problematic if the effect of the laterals is not correctly modelled. In this work it is investigated what the impact of RJD laterals is on the pressure transients for both single and dual porosity reservoirs. A semi-analytic model for the calculation of the transient well pressure that accounts explicitly for the RJD well geometry is developed and validated with a detailed numerical simulation. The results show that changes in the lateral configuration affect the pressure transients significantly. In particular for single porosity media, the laterals affect the pressure transients in ways that cannot be captured by representing the stimulation by a skin factor. Since the RJD process is unsteered and the exact configuration of the laterals uncertain, the model may potentially assist in estimating the effectiveness of the stimulation such as the achieved reach of the laterals. Although the work was carried out in the context of RJD application in geothermal reservoirs, the presented model approach can be extended to multi-lateral wells in oil or gas reservoirs.

Advanced Concepts in Naturally Fractured Reservoirs with Analysis of Field Data

Dual porosity reservoir is mainly defined as fractured reservoir. The Two porosities are included for fracture and matrix, Flow in the fractures, oil storage in the matrix. Dual Permeability reservoir are those pay zones with flow in both the fracture and matrix systems. Single porosity means matrix, dual porosity means both matrix and fractures and triple porosity means matrix, fractures and vugs. The description of displacement mechanisms in fractured reservoirs can be construed as: oil expansion, gravity forces, capillary forces, balance of gravity and capillary forces, diffusion and convection. Fractures are usually found in limestone and dolomites due to solution, re-crystallization. Two categories of fractures are available such as: Open Fractures and Closed Fractures which depend mainly on circulation water and precipitation. Fractures which are closed at surface conditions may be open in reservoir conditions. Fractures related to folding axis are such as: longitudinal fractures, along the folding axis and transverse fractures, perpendicular to the folding axis and diagonal fractures, in relation with the folding axis. There are some pivotal issues and expressions in fractured reservoirs that in this paper, an approach to the advanced concepts in Naturally Fractured Reservoirs has been studied.

An improved response equation of dual laterolog in dual porosity reservoirs and its solution scheme and applications in fractured reservoirs

Many fractured reservoirs are dual porosity reservoirs including matrix pores and fractures, which both contribute to the porosity. However, previous studies either ignored the effect of pores or fractures on dual laterolog, or had special application conditions. Considering the joint contribution of pores and fractures, a response equation of dual laterolog in dual porosity reservoirs is established. First, based on a borehole model with a vertical fracture in dual porosity reservoirs, fracture porosity equations are established in the investigation depths of deep and shallow laterologs, respectively. Using Archie's equations, the response equations of deep and shallow laterolog resistivities are derived, respectively. Then, the response equation, which is similar to the traditional equation of dual laterolog in fractured tight reservoirs, is established. It contains three unknown parameters, i.e. fracture width, fracture cementation exponent and matrix cementation exponent. To solve the equation, a virtual core model is proposed to estimate the fracture cementation exponent by fracture width. The estimation method of matrix cementation exponents is established by empirical formulas. Then, the response equation can be transformed into a nonlinear equation with one unknown parameter of fracture width, and conventional iterative methods can be employed to solve it and obtain the fracture width. Using the response equation and the solution scheme, the change characteristics of fracture cementation exponents in different fractured reservoirs are first analyzed. It shows that the fracture cementation exponents increase with the fracture widths, and they decrease with the increase of the ratio of formation water resistivity to unfractured reservoir resistivity. The applications indicate that the equation and solution scheme can obtain relatively accurate fracture widths quickly in dual porosity reservoirs, and they are recommended for dual porosity reservoirs with high fracture angel (>70°) and low fracture density (<1/3.78 m-1). The findings of this study can help better understanding of the different contributions of fractures and pores to dual laterolog responses in dual porosity reservoirs, and they can provide an alternative solution for evaluating dual porosity reservoirs.

Employing Deep Learning Neural Networks for Characterizing Dual-Porosity Reservoirs Based on Pressure Transient Tests

Abstract The deep learning model constituting two neural network models (i.e., densely connected and long short-term memory) has been applied for automatic characterization of dual-porosity reservoirs with infinite, constant pressure, and no-flow external boundaries. A total of 16 different prediction paradigms have been constructed (one classifier to identify the reservoir models and 15 regressors for predicting the dual-porosity reservoir characteristics). Indeed, wellbore storage coefficient, CDe2S, skin factor, interporosity flow coefficient, and storativity ratio have been estimated. The training pressure signals have been simulated using the analytical solution of the governing equations with varying noise percentages. The pressure drop and derivation of the noisy synthetic signals serve as the input signals to the intelligent scenario. The hyperparameters of the intelligent model have been carefully adjusted to improve its prediction performance. The trained classification model attained 99.48% and 99.32% accuracy over the training and testing datasets. The separately trained 15 regressors converged well to estimate the reservoir parameters. The model performance has been demonstrated with three uniquely simulated and real-field cases. The results indicate that the compiled prediction model can accurately identify the reservoir model and estimate the corresponding characteristics.

Analysis and Application of Fractured Carbonate Dual-Media Composite Reservoir Model

Fractured carbonate reservoirs are different from conventional reservoirs and generally develop fractures. Conventional reservoir well test performance analysis can only obtain the formation parameters and discharge radius around a single well. For vertical wells in fractured carbonate reservoirs, we can establish a dual-porosity composite reservoir model for well testing interpretation and analysis based on the actual conditions of the reservoir and combined with geological knowledge. The model can be applied to formations with different reservoir properties in the near-well and far-well areas around a single well to analyze the fracture parameters (elastic reserve ratio and channeling coefficient) and the effective flow capacity of formation fluids in the two areas. On this basis, we use the interpretation of actual production wells to verify the accuracy of the model and analyze the influence of reservoir parameters and fracture parameters on the theoretical curve.

A New Method for Calculating the Cementation Exponent of Triple-Porosity Media Reservoirs

The value of a cementation exponent, usually obtained by rock and electricity experiments, significantly affects the calculation of water saturation, thickness of the hydrocarbon reservoir, and recovery rate. The determination of the cementation exponent for porous-media reservoirs has been a challenge because of the limited core sampling. A new method was proposed to determine the value of cementation exponent for complex triple-porosity media reservoirs in the work. Firstly, the work discussed the effects of fractures and nonconnected vugs on the cementation exponent of the reservoir as well as the calculation method of the cementation exponent of the dual-porosity media reservoir. Then, a new model for calculating the cementation exponent of triple-porosity media reservoirs was derived by combining the Maxwell-Garnett theory and series-parallel theory, which matched with the real physical-experiment data of rocks. The results showed that the fractures decreased the cementation exponent of the reservoir but the vugs increased. The mixture of matrix pores, fractures, and vugs made the value of the cementation exponent of the triple-porosity media reservoir vary around 2.0. The conductivity of the triple-porosity media reservoir was the external macroscopic expression of the microscopic conductive network. The new calculation model of the cementation exponent proposed in the work could reasonably predict the cementation exponent of the strongly inhomogeneous triple-porosity media reservoir.

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Petroleum rock mechanics: An area worthy of focus in geo-energy research

Mathematical Simulation about Gas Transport in a Dual-Porosity Tight Gas Reservoir considering Multiple Effects

Threshold pressure gradient, gas slippage, and stress sensitivity have important effects on the production of a tight gas reservoir. But previous studies only focused on one or two of these effects. In this study, a mathematical model considering these three effects was established to describe gas transport in a dual-porosity tight gas reservoir. Threshold pressure gradient, gas slippage, and stress sensitivity are simultaneously considered in the velocity term of continuity equation which is mainly different from the previous research results. The partial differential equation and definite solution condition are discretized by a central difference method. A finite difference procedure was compiled and applied to solve this numerical model and predict the productivity of a production well in a dual-porosity tight gas reservoir. The difference between the predicted and tested cumulative production is less than 10%, which indicates that the proposed mathematical model can be used to describe the characteristics of gas flow in the dual-porosity tight gas reservoir. Then, gas productivity of five different scenarios considering these effects was compared. Results show that both stress sensitivity and threshold pressure gradient are negatively correlated with gas production, while gas slippage is positively correlated with gas production. Among them, stress sensitivity has the greatest impact on the production of a dual-porosity tight gas reservoir. Overall, these three effects have great influence on the development of the dual-porosity tight gas reservoir, which should be considered in the production prediction.

Analyzing fluid flow characteristics in a dual-porosity reservoir with an elastic outer boundary

Analyzing fluid flow characteristics in a dual-porosity reservoir with an elastic outer boundary

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.

A Semianalytical Two-Phase Imbibition Model in Dual-Porosity and Dual-Permeability Reservoirs

The pressure transient behavior of water injection well has been extensively investigated under single-phase flow conditions. However, when water is injected into formation, there are saturation gradients within the water flooded area. Additionally, water imbibition is essentially important for oil displacement in dual-porosity and dual-permeability (DPDP) reservoirs. In this work, a novel semianalytical two-phase flow DPDP well test model considering both saturation gradient and water imbibition has been developed. The model was solved by the Laplace transform finite difference method. Type curves were generated, and flow regimes were identified by the model. The model features and effect of parameters were analyzed. Results show that water imbibition reduces the advancing speed of water drive front in the fracture system and slows down the water cut raising rate and the expansion speed of the two-phase zone in the fracture system. Therefore, the fluid exchange between the fracture and matrix systems becomes more sufficient and more oil will be recovered from the DPDP reservoir. The shape of pressure curves is similar for the single-phase and two-phase flow DPDP model, but the position of the proposed model is above the curves of the single-phase model. Shape factor mainly influences the interporosity period of the pressure derivatives. Water imbibition has a major effect on the whole system radial flow period of the curves. The findings of this study can help for better understanding of the oil/water two-phase flow pressure transient behavior in DPDP reservoirs considering saturation gradients and water imbibition.

Practical pressure-transient analysis solutions for a well intercepted by finite conductivity vertical fracture in naturally fractured reservoirs

The semi-analytical or numerical solutions are the most used for pressure-transient analysis (PTA) for finite-conductivity fractured wells in naturally fractured reservoir now. However, the semi-analytical solutions are time-consuming and easily lead to inaccuracy at low fracture conductivity with less discretized segments. The numerical solutions are more time-consuming and usually face convergence and stability problems. These solutions are not convenient for practical well test analysis in Oilfield. Our motivation for this paper is to develop simply, quickly and stably analytical PTA solutions for finite-conductivity fractured wells in naturally fractured reservoir that can serve the well test analysis in Oilfield. We first derive a transformation method which can extend finite-conductivity fracture solutions in homogeneous reservoir to dual-porosity reservoir. Thereafter, analytical solutions for finite-conductivity fractured wells in homogeneous reservoir are presented. Then we provide a series of analytical finite-conductivity fracture solutions in dual-porosity reservoir under different boundary conditions based on the transformation method and homogeneous reservoir solutions. Six solutions given in the published literatures are used to verify the proposed solutions under different dimensionless fracture conductivity (FcD). Results indicate that (a) the proposed solutions are valid for FcD>1 with maximum error (5%) and this error will quickly decreases to around 1%; (b) the proposed solutions are applicable for infinite, closed and constant-pressure boundary conditions; (c) the proposed solutions can be extended to triple-porosity naturally fractured reservoirs after changing the f(s) function; (d) the proposed solutions are accurate and can greatly shorten the time of well test interpretation comparing to conventional solutions. Finally, the pressure-buildup data from Shunbei Oilfield is interpreted using the proposed solutions to verify its feasibility and practicability. The findings of this work can help for better understanding of its potential in quick well test analysis for field cases.

Investigation of rock properties distribution effect on pressure transient analysis of naturally fractured reservoirs

Naturally fractured reservoirs (NFRs) are considered as one of the main resources of oil and gas around the world. The nature of fractures in this kind of reservoirs splits these reservoir rocks into two parts; matrix and fracture. In these two media, geometrical properties like matrix block size and also petrophysical properties such as porosity and permeability cannot considered to be constant and they usually contain heterogeneity in extent of the reservoir. In this study, a statistical distribution concept is used to be able to model variance of properties including matrix block size, matrix and fracture permeability, and matrix and fracture porosity as independent statistical variables. For the purpose of investigating effect of the five aforementioned properties distribution on pressure transient analysis (PTA) plots, five distinct cases of property distributions are considered with their corresponding precise statistical modeling applied on governing flow equation of a dual-porosity base case reservoir model. Abovementioned distributed parameters are included in semi-analytically derived dual porosity reservoir models and results are compared to their corresponding constant-value response. In each case the constant parameter is the median of corresponding statistical distribution. The statistical approach is validated using numerical modeling and field data applications are also presented. Different unimodal and bimodal matrix properties (block size, permeability, and porosity) distribution have slight to intense effects on PTA plots of an NFR. In matrix block size and porosity distribution cases, lower values, and in matrix permeability distribution case, higher values of the range dominate the pressure behavior of the fractured system. On the other hand, although fracture permeability and porosity distribution can shift PTA plots of the model but the effect is not significant and both fracture permeability and porosity distribution can be represented by constant representative values instead of a statistical model. It is worth mentioning that all matrix properties bimodal distribution has a common signature on PTA plots which is similar to the triple porosity reservoir response (i.e. the presence of double-bump descent on pressure derivative plot).

Investigation on the pressure response behavior of two-layer vertical mixed boundary reservoir: field cases in Western Sichuan XC gas field, China

Pressure response behavior of two-layered reservoir with a vertical mixed boundary is easy to be mistaken for that of the radial composite reservoir or dual-pore reservoir. It is difficult to fit the pressure response curve and easy to obtain abnormal parameter values using a misunderstood model. In this paper, we present the interpretation of three different types of pressure responses of vertical mixed boundary reservoir by our proposed models, where the diagnostic window and feature value are captured for different mixed boundary types. Results show that the mixed boundary with closed boundary and infinite-acting boundary induces the fake pressure response of a radial composite reservoir with poor permeability outer zone. The mixed boundary with the main constant-pressure and non-main closed boundary produces a fake pressure response of a dual-porosity reservoir. The diagnostic window of pressure response curves shape can easily capture the mixed boundary type, and the feature value of the feature values of pressure response value can quickly obtain the permeability ration of one layer. Aiming at different representative types of pressure response cases in the western Sichuan XC gas field, China, we innovatively analyze them from a different perspective and get a new understanding of pressure response behavior of vertical mixed boundary, which provides a guideline for the interpretation of layered oil and gas reservoir with the complex boundary in the vertical direction.

A Practical Methodology for Production Data Analysis in Carbonate Reservoirs Using New Decline Type Curves

Carbonate reservoirs typically have complex pore structures, so the production wells typically have high production in the early production stage, but they decline rapidly. It is highly challenging to achieve accurate interpretation results. In this paper, a new and practical methodology for production data analysis of fractured and fractured-vuggy carbonate reservoirs is proposed. Firstly, analytical solutions to characterize the different multipore media and simulate transient production behavior of fractured and fractured-vuggy carbonate reservoirs during the transient flow regime are presented. Then, a new function f q D and f ′ q D that related to the dimensionless production rate is introduced, and a series of new decline type curves are drawn to make a clear observation of different flow regimes. In addition, the effects of the storativity ratio, interporosity flow coefficient, skin factor, and dimensionless radial distance of external boundary on production performance are also analyzed. Finally, two example wells from the fractured and fractured-vuggy carbonate reservoirs are used to perform rate decline analysis with both the Blasingame type curves and the new type curves. The validation of the new method is demonstrated in comparison to the results of well test interpretation. The results show that the curves of 1 / f ′ q D vs. t D are ∧ -shaped for dual-porosity reservoirs and M -shaped for triple porosity reservoirs and also indicate that the interpreted parameters such as permeability, skin factor, storativity ratio, and interporosity flow coefficient using new decline type curves are aligned well test interpretation. In correlation with other traditional well test analysis, this approach effectively reduces the multisolution probability of interpretation.