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Schematic diagram: (a). Fractured-vuggy carbonate reservoirs with multi-branched fractures. (b) the system of matrix, fractures, vugs. (c) 2D flow sketch map for a cell (Wang et al. 2014).
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In the past few decades, scholars have made great breakthroughs in the study of well test analysis of carbonate rock. The previous studies are based on horizontal wells, straight wells, fractured wells, and inclined wells. With the development of fracturing technology, acid fracturing technology is considered to be the most effective measure to dev...
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... they also think that although non-Darcy flow may occur, the assumption of Darcy (linear) flow for oil at near the wellbore is reasonable because of rela- tively low velocity of oil flow. Fractured-vuggy carbonate reservoirs with multi-branched fractures are naturally structured by matrix system, natural fractures system, vugs system. (See Fig. 1a,b). Figure 2 shows that the phys- ical modeling scheme of fractured-vuggy carbonate medium. The assumptions of physical model are as ...
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... reservoir models for vertical wells in carbonate reservoirs have been studied 4,5,23,34 . Figure 1c shows the flow process. Derivation and description of details for reservoir model can be found in Appendix B of Supplementary material. ...
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... the angle of the fractures is greater than 50°, the flow characteristic in early time is nearly not affected by the angle. Figure 10 shows the effect of the conductivity on type curves. Both the pressure and its derivative curves show this effect mainly occurs in the early time. ...
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... the conductivity for each fracture is different, how the conductivity affects the type curves? As shown in Fig. 11, the uniform conductivity for case 3 exhibits the complete flow characteristics, the starting time of the lin- ear flow becomes late and the pressure depletion increases as the each fracture conductivity decreases. This point is coincided with the analysis above under the uniform conductivity. Figure 12 shows the effect of the fracture ...
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... point is coincided with the analysis above under the uniform conductivity. Figure 12 shows the effect of the fracture length on type curves. The curves exhibit the complete flow characteristics when all fracture length is set to be 0.5. ...
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... this section, a field case is selected to validate the presented solution. Well A located in the western oil field of China is selected. The well test data is shown in Fig. 13. The reservoir thickness is 25 m and the effec- tive porosity (matrix + fractures + vugs) is 0.12. The oil viscosity is 0.00152 Pa▪s and the total compressibility is 0.0014 MPa −1 . The production of well is 120 m3/d. According to well test data, we have drawn the pressure and pressure derivative curves in Fig. 13. Pressure derivative ...
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... The well test data is shown in Fig. 13. The reservoir thickness is 25 m and the effec- tive porosity (matrix + fractures + vugs) is 0.12. The oil viscosity is 0.00152 Pa▪s and the total compressibility is 0.0014 MPa −1 . The production of well is 120 m3/d. According to well test data, we have drawn the pressure and pressure derivative curves in Fig. 13. Pressure derivative curves show 1/4 and 1/2 slopes straight lines, which implies that bi-linear flow and linear flow occur in the early time. However, the inter-porosity flow region is not found in the figure. Therefore, g(s) is set to 1 in our presented model. Furthermore, we can determine those unknown parameters use the present ...
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Citations
... Dyke et al. (1995) demonstrated that NFRs are distinguished by initial severe losses followed by a gradual decline over time, whereas mud loss through pores exhibits a slow start and gradually increases over time. In the literature, such reservoirs are mathematically represented as single-and double-porosity models (Wennberg et al. 2006;Golghanddashti 2011;Moinfar et al. 2011;Rezaee 2015;Abbasi et al. 2017;Wang et al. 2018). Various attempts have been made to develop analytical and numerical models to measure mud loss through NFR (Liétard et al. 1999;Lavrov 2006;Majidi et al. 2010;Razavi et al. 2017;Dokhani et al. 2019). ...
Drilling becomes extremely challenging when dealing with naturally fractured reservoirs (NFR). A comprehensive solution is developed in this study to perform qualitative analysis on drilling fluid loss rate and volume to examine how they can be affected by NFR characteristics, drilling fluid rheology, leakoff phenomenon, and wellbore condition. In this regard, the solution is applied to generate type curves to facilitate the sensitivity analysis (refer to the provided Supplementary Materials). The presented solution accounts for not only drilling fluid pseudoplasticity in the total system but also matrix medium under wellbore constant pressure assumption (by including dimensionless matrix contribution parameter). It is also able to measure mud loss advancement not only through NFR but also through homogeneous reservoirs. The developed solution is validated by reducing it to the preexisting solution (designed for Newtonian fluid case) by incorporating assumptions into it. The result demonstrates the significance of NFR properties and drilling fluid pseudoplasticity on the leakoff phenomenon and total loss volume, especially when constant pressure is established inside the wellbore. The finding reveals that three periods can be identified through generated type curves depending on NFR characteristics, drilling fluid rheology, and leakoff coefficient. Therefore, different drilling fluids with specific pseudoplasticity should be used in each period to mitigate drilling fluid loss effectively. In this regard, the study is supposed to design drilling fluid in a way to maintain its pseudoplasticity at a higher level at early and late times, while being maintained at a lower level during the transient period, a critical aspect for managed pressure drilling techniques, particularly in the context of dual-gradient drilling applications. Additionally, a procedure should be implemented to lessen the transient period while attempting to keep drilling fluid advancement occurrence at a lower rate, which shows that drilling fluid pseudoplasticity can be used as an effective tool to manage this period. The obtained result also indicates that the importance of drilling fluid rheology to control total loss volume is greater for NFR with higher leakoff than with lower leakoff. Furthermore, the greater the differential pressure inside the wellbore, the greater the importance of mud rheology to reduce drilling fluid loss. The outcome of the study not only facilitated qualitative and quantitative analyses through NFR but also enabled decision-makers to instantaneously select optimal wellbore conditions and drilling fluid pseudoplasticity.
... At present, the research methods of reasonable productivity mainly include numerical simulation, systematic well testing, and statistical and analogy methods [14][15][16][17][18][19]. For fault−controlled fracture−cave reservoirs characterized by coexisting pipe flow and seepage fluids [20], the numerical simulation method based on the continuum theory is difficult to be applied to the research and determination of single−well productivity [21]. Statistical methods need too many data to established a unified expression to show the essential factors that affect the productivity of a single well. ...
The largest ultra−deep (>7000 m) strike−slip fault−controlled oilfield was found in the tight Ordovician carbonates in the Tarim Basin. Because oil production wells in the Fuman Oilfield generally have bottom water, a reasonable production design is of significant importance for extending the water−free oil recovery period and improving oil recovery. However, there is no economical and effective quantitative method to determine a reasonable production capacity and a corresponding reasonable work system for stable−production wells in fault−controlled fractured carbonate reservoirs. In this contribution, we integrated the dynamic and static data of different types of wells in the Fuman Oilfield. It was found that there is a positive relationship between well−controlled dynamic reserves and reasonable productivity, and the productivity corresponding to the upper limit of the reserve can be defined as reasonable productivity. Further, we proposed a correlation equation between well−controlled dynamic reserves and reasonable productivity that shows the reasonable productivity of a stable well from the well−controlled dynamic reserve, which was obtained by combining the well productivity test and analogous well productivity test methods. The relationship between the reasonable productivity per unit nozzle and the rational productivity was obtained according to the determined matching relationship between the reasonable productivity of the stable−production well and the nozzle. The application results show that it can not only quickly determine the reasonable production capacity of stable−production wells but also deepen the understanding of the quantitative characteristics of the production capacity of the Fuman Oilfield. It also provides insight in the rational production allocation of new wells and optimize the development design, which supports the 1500 × 104 bbl/year oil production from the ultra−deep fractured carbonate reservoirs along the strike−slip fault zones in the Tarim Basin.
... For the simulation of flow in vuggy carbonate formations, where the pore space is composed of the porosity in the porous medium, fractures, and vugs, it is a common practice to apply the multi-continuum approach, e.g., dual porosity or triple porosity models. In this approach, the network of vuggy cavities is considered as a secondary/tertiary porosity system with unitary porosity and high permeability, in which flow obeys Darcy's law, [13][14][15][16][17][18][19][20][21][22][23][24]. In a recent work, Lei et. ...
Hydrodynamics characterization and analysis is an essential part in studying mineral dissolution in porous media with complex heterogeneous pore structures including embedded cavities. Cavities affect the pore-scale pressure and flow distribution in the surrounding porous matrix. Transport of the dissolved solute, concentration gradient, and thermodynamic driving forces in that area will be affected as a result of local flow features. Given the properties of cavities and porous media, vorticities may form, and the cavity may partially or fully contribute to the overall flow. Depending on the shape and alignment of the cavity with respect to the direction of general flow, fluid flow will be focused at certain locations on the cavity boundary. Reaction hotspots can form as a result of the facilitated mineral dissolution at those locations. A rigorous flow modeling approach that preserves the flow features inside the cavity and in the porous matrix is used. Stokes flow and seepage flow are applied as two different physics governing the fluid flow in a fluid-filled cavity and a highly permeable sediment-filled cavity consecutively. The analytical model framework permits capturing the detailed flow structure of a single-phase fluid at the curved interface of a prolate spheroidal cavity. The solutions for flow are used within a fully coupled, fully implicit reactive transport simulator to investigate the mineral dissolution in the porous host matrix. The cavity aspect ratio and slip parameter at the border are investigated as the two parameters that affect the dissolution. The simulation results showed that the reaction hotspots are mainly located on the border of the cavity where the influent enters and leaves the cavity. The midpoint between them is where the minimum mineral dissolution was placed. Approximating the cavity as a highly permeable sediment-filled porous zone showed a higher effective reaction rate compared to the fluid-filled cavity. The cavity aspect ratio showed to have a significant impact on the effective reaction rate of the investigated cases. The cavities with a shape closer to a sphere show a higher effective reaction rate.
... The pressure equation is elliptic and the transport equations of fluids are hyperbolic. These governing equations have been implemented in various studies to predict fluid flow in naturally fractured reservoirs 7 and even in pore-scale modelling of heterogeneous porous media 8 . Moreover, the hydrology community relies on similar numerical models to simulate groundwater movement, contaminants transport in aquifers chemical reactions between minerals 9,10 . ...
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... Schematic diagram of HDW in a fractured-vuggy carbonate gas reservoir. Flow sketch map for a cell[29]. ...
To improve the carbonate gas reservoir development and production, highly deviated wells (HDW) are widely used in the field. Production decline analysis of HDW is crucial for long-term gas reservoir development. However, it is a new challenge to incorporate the complex pore structure of naturally fractured-vuggy carbonate gas reservoirs and evaluate the production performance of HDW. This paper presents a semianalytical model to analyze the pressure and production behavior of HDW in naturally fractured-vuggy carbonate gas reservoirs, which consist of fractures, vugs, and matrix. The primary flow occurs only through the fracture and the outer boundary is closed. Introducing pseudopressure and pseudotime, the Laplace transformation, Fourier transformation, and its inverse and Stehfest numerical inversion were employed to establish a point source and line source solutions. Furthermore, the validity of the proposed model was verified by comparing a field data from the Arum River Basin in Turkmenistan. Finally, the effects of major parameters on the production decline curves were analyzed by using the proposed model and it was found that they had influences at different stages of gas production history and the sensitivity intensity of each parameter was different. With its high efficiency and simplicity, this semianalytical model will serve as a useful tool to evaluate the well production behavior for the naturally fractured-vuggy carbonate gas reservoirs.
... Recently, the fluid flow and transport behavior in fractured-vuggy porous media have been analyzed with theoretical methods 3,9,[29][30][31][32][33][34] . Wu et al. [29][30][31] investigated multiphase flow in fractured-vuggy reservoirs using triple-continuum models. ...
... And in their model, the pore networks in acidized region were conceptualized as multi-branched wormholes (i.e., the pore networks in acidized region were simplified as multi-branched high-permeability channels), which were used to bridge the gap between the outer region of triple medium and the wellbore. In 2018, Wang et al. 34 also investigated flow characteristics in fractured-vuggy carbonate reservoirs using semi-analytical model considering wormholes as multi-branched fractures. Other scholars proposed composite model to study the pressure transient characteristics in fractured-vuggy reservoirs within which the pore networks in acidized region are equivalent to homogeneous medium of Euclidean geometry 35,36 . ...
Acidizing is one of the widely used technologies that makes the development of naturally fractured-vuggy reservoirs effective. During the process of acidizing, carbonate minerals are dissolved by hydrochloric acid, which can create high conductivity channels and wormholes to connect fractures and pores. In this work, a new analytical model, incorporating the heterogeneity of the pore networks into acidizing region, is proposed to study the flow characteristics in acidized fractured-vuggy reservoirs. The model is coupled by an acidized inner region and a conceptualized outer region of common triple medium. The porosity and permeability of inner region, which are rather heterogeneous and disordered when observed at different length scales, can be well addressed by fractal theory. The properties of the outer region can be described with three basic parameters: the matrix block size LM, the space interval of fracture LF and the radius of the vug Lv. Results show that the flow characteristic curves can be characterized by six flow stages (i.e. wellbore storage stage, radial flow stage in the interior region, fracture-vug inter-porosity flow stage, transition flow stage, fracture-matrix inter-porosity flow stage and external boundary response stage). It can be applied to estimate reservoir parameters for uncertainty reduction using inverse modeling.
More and more attention has been paid to the study of flow properties in fractured-vuggy reservoirs because lots of such reservoirs have been found worldwide with significant gas production and reserves. In order to improve carbonate gas reservoir production, highly deviated wells (HDW) are widely used in the field. However, it is very difficult to consider the complex pore structure of fractured-vuggy reservoirs and evaluate the pressure transient behaviors of HDW. This paper presents a semi-analytical model that analyzed the pressure behavior of HDW in fractured-vuggy carbonate gas reservoirs which consist of fractures, vugs and matrix. Introducing pseudo-pressure; Fourier transformation, Laplace transformation, and Stehfest numerical inversion were employed to establish a point source and line source solutions. Furthermore, the validity of the proposed model was verified by comparing with two existing pressure transient models. Then the flow characteristics were analyzed thoroughly by examining the pressure derivative curve which can be divided into five flow stages. The physical meanings of the model parameters were analyzed through sensitivity analysis. Finally, a field case was successfully used to show the application of the proposed semi-analytical model. The study contributes to the highly efficient evaluation of the pressure transient behaviors for HDW in fractured-vuggy carbonate gas reservoirs.KeywordsFractured-vuggy carbonate gas reservoirHighly deviated wellMatrixPressure transient behaviorsWell testing
Tight multi-medium oil reservoirs are the main source of hydrocarbon resources around the world. Acid fracturing is the most effective technology to improve productivity in such reservoirs. As carbonates are primarily composed of dolomite and calcite, which are easily dissolved by hydrochloric acid, high-permeability region will be formed near the well along with the main artificial fracture when acid fracturing is implemented in tight multi-medium oil reservoirs. In this study, a comprehensive composite linear flow model was developed to simulate the transient pressure behavior of an acid fracturing vertical well in a naturally fractured vuggy carbonate reservoir. By utilizing Pedrosa’s substitution, perturbation, Laplace transformation and Stehfest numerical inversion technology, the pressure behavior results were obtained in real time domain. Furthermore, the result of this model was validated by comparing with those of previous literature. Additionally, the influences of some prevailing parameters on the type curves were analyzed. Moreover, the proposed model was applied to an acid fracturing well to evaluate the effectiveness of acid fracturing measures, to demonstrate the practicability of the proposed model.
Fluid flow dynamics in fracture-caved carbonate reservoirs are usually simulated using the traditional continuum flow theory. With the presence of large karst caves, fluid flow in these reservoirs may not always obey the Darcy law. Actually it follows the pipe flow, free flow or Darcy law-coupled free flow. The continuum flow theory is therefore not able to accurately capture the underlying flow dynamics within the large karst caves. Large caves in fracture-caved reservoir are widely interconnected with a series of tectonic fractures, which resembles a string of beads and is thus defined as a multi-cave multi-fracture reservoir unit. By simplifying the configuration of actual fracture-caved carbonate reservoir as a multi-cave multi-fracture series connection domain, this paper develops a novel mathematical model to accurately describe the complicated fluid behaviors coupling Darcy flow and free flow, among of which the fluid flow in fractures still obeys the Darcy law while that in large caves is assumed to free flow. A semi-analytical solution of the proposed model is then derived in order to plot the dimensionless typical curve for rate transient analysis (RTA) in fracture-caved reservoir. Factors affecting the characteristics of the RTA typical curve are further investigated. Finally, case study in a bead-string fracture-caved reservoir unit is performed to estimate the reservoir and well properties using the proposed model. The deep understandings can provide good insights for reasonable exploitation of this type of fracture-caved carbonate reservoirs.
