Dual-Porosity Dual-Permeability Rate Transient Analysis for Horizontal Wells with Nonuniform and Asymmetric Hydraulic Fractures

2021 ◽  
Author(s):  
Chao Liu ◽  
Dung T. Phan ◽  
Younane N. Abousleiman
Keyword(s):  
Transient Analysis ◽  
Horizontal Wells ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Rate Transient Analysis ◽  
Permeability Rate

Rate transient analysis of fractured horizontal wells

2020 ◽  
pp. 62-67
Author(s):  
R.R. Urazov ◽  
◽  
A.Ya. Davletbaev ◽  
A.I. Sinitskiy ◽  
A.Kh. Nuriev ◽  
...  
Keyword(s):  
Transient Analysis ◽  
Horizontal Wells ◽  
Rate Transient Analysis ◽  
Fractured Horizontal Wells

An Integrated Geologic and Engineering Assessment of Fracture-Flow Potential in the Ratawi Reservoir of the Wafra Field, Partitioned Neutral Zone

2008 ◽  
Vol 11 (06) ◽  
pp. 1071-1081 ◽  
Author(s):  
Amy Whitaker ◽  
C. Shah Kabir ◽  
Wayne Narr
Keyword(s):  
Transient Analysis ◽  
Water Injection ◽  
Flow Simulation ◽  
Simulation Models ◽  
Dual Porosity ◽  
Fracture Flow ◽  
Fractured Reservoir ◽  
Horizontal Drilling ◽  
Rate Transient Analysis ◽  
Production Characteristics

Summary The extent to which fractures affect fluid pathways is a vital component of understanding and modeling fluid flow in any reservoir. We examined the Wafra Ratawi grainstone for which production extending for 50 years, including recent horizontal drilling, has provided some clues about fractures, but their exact locations, intensity, and overall effect have been elusive. In this study, we find that a limited number of total fractures affect production characteristics of the Ratawi reservoir. Although fractures occur throughout the Wafra field, fracture-influenced reservoir behavior is confined to the periphery of the field where the matrix permeability is low. This work suggests that for the largest part of the field, explicit fractures are not necessary in the next-generation Earth and flow-simulation models. The geologic fracture assessment included seismic fault mapping and fracture interpretation of image logs and cores. Fracture trends are in the northeast and southwest quadrants, and fractures are mineralized toward the south and west of the field. Pressure-falloff tests on some peripheral injectors indicate partial barriers, and most of these wells lie on seismic-scale faults in the reservoir, suggesting partial sealing. A few wells show fractured-reservoir production characteristics, and rate-transient analysis on a few producers indicates localized dual-porosity behavior. Producers proximal to dual-porosity wells display single-porosity behavior, however, to attest to the notion of localized fracture response. The spatially restricted fracture-flow characteristics appear to correlate with fracture or vug zones in a low-permeability reservoir. Presence of fracture-flow behavior was tested by constructing the so-called flow-capacity index (FCI), the ratio of khwell (well test-derived value) to khmatrix (core-derived property). Data from 80 wells showed khmatrix to be consistently higher than khwell, a relationship that suggests insignificant fracture production in these wells. Introduction The Wafra field is in the Partitioned Neutral Zone (PNZ) between Kuwait and Saudi Arabia, as shown in Fig. 1. The field has been producing since the 1950s and has seen renewed drilling activity since the late 1990s, including horizontal drilling and implementation of peripheral water injection (Davis and Habib 1999). The Lower Cretaceous Ratawi formation contains the most reserves of the producing intervals at Wafra. The Ratawi oolite (a misnomer--it is a grainstone) reservoir has variable porosity (5 to 35%) and permeability that ranges from tens to hundreds of md (Longacre and Ginger 1988). The main Wafra structure is a gentle (i.e., interlimb angle >170°), doubly plunging anticline trending north-northwest to south-southeast, which culminates near its northern end. The East Wafra spur is a north-trending branch that extends from the center of the main Wafra structure. As seen in Fig. 1, relief on the Main Wafra structure exceeds that on East Wafra. The Ratawi oolite in the Wafra field has been studied at length, and various authors have reported geologic and engineering elements, leading to reservoir characterization and understanding of reservoir performance. Geologic studies are those of Waite et al. (2000) and Sibley et al. (1997). In contrast, Davis and Habib (1999) presented implementation of peripheral water injection, whereas Chawathé et al. (2006) discussed realignment of injection pattern owing to lack of pressure support in the reservoir interior. Previous studies considered the reservoir to behave like a single-porosity system. But recent image-log fracture interpretations indicate high fracture densities, suggesting that the implementation of a dual-porosity model may be necessary because the high impact of fractures during field development has been recognized in some Middle East reservoirs for more than 50 years (Daniel 1954). Static and dynamic data are required to characterize fracture reservoir behavior accurately (Narr et al. 2006). Geologic description of the fracture system, by use of cores, borehole images, seismic data, and well logs, does not in itself determine whether fractures affect reservoir behavior. While seismic and some image logs were available to locate fractures in the Wafra Ratawi reservoir, no dynamic testing with the specific objective of understanding fracture impact has occurred. So, to determine whether fractures influence oil productivity significantly, we used diagnostic analyses of production data and well tests of available injectors. The assessment of fracture effects in the Ratawi reservoir will be used to guide the next generation of geologic and flow-simulation models. Dynamic data involving pressure and rate have the potential to reveal the influence of open fractures in production performance. Unfortunately, pressure-transient testing on single wells does not always provide conclusive evidence about the presence of fractures with the characteristic dual-porosity dip on the pressure-derivative signature (Bourdet et al. 1989). That is because a correct mixture of matrix/fracture storativity must be present for the characteristic signature to appear (Serra et al. 1983). In practice, interference testing (Beliveau 1989) between wells appears to provide more-definitive clues about interwell connectivity, leading to inference about fractures. In contrast to pressure-transient testing, rate-transient analysis offers the potential to provide the same information without dedicated testing. In this field, all wells are currently on submersible pumps. Consequently, the pump-intake pressure and measured rate provided the necessary data for pressure/rate convolution or rate-transient analysis. We provide the Ratawi-reservoir case study primarily as an example of the integration of diverse geologic and engineering data to develop an assessment of fracture influence on reservoir behavior. It illustrates the use of production-data diagnostic tests to determine fracture influence in the absence of targeted fracture-analysis testing. The workflow can be applied to similar static/dynamic problems, such as fault-transmissivity determination. Secondly, this analysis illustrates the process of deciding that fractures, although present throughout the reservoir, may not lead to widespread fractured-reservoir characteristics (e.g., Allan and Sun 2003).

The Interpretation Technique of Rate Transient Analysis Data in Fractured Horizontal Wells

2021 ◽  
Author(s):  
Ruslan Rubikovich Urazov ◽  
Alfred Yadgarovich Davletbaev ◽  
Alexey Igorevich Sinitskiy ◽  
Ilnur Anifovich Zarafutdinov ◽  
Artur Khamitovich Nuriev ◽  
...  
Keyword(s):  
Hydraulic Fracturing ◽  
Transient Analysis ◽  
Horizontal Well ◽  
Horizontal Wells ◽  
Data Interpretation ◽  
Analysis Data ◽  
Well Logging ◽  
Rate Transient Analysis ◽  
Fractured Horizontal Well ◽  
Fractured Horizontal Wells

Abstract This research presents a modified approach to the data interpretation of Rate Transient Analysis (RTA) in hydraulically fractured horizontal well. The results of testing of data interpretation technique taking account of the flow allocation in the borehole according to the well logging and to the injection tests outcomes while carrying out hydraulic fracturing are given. In the course of the interpretation of the field data the parameters of each fracture of hydraulic fracturing were selected with control for results of well logging (WL) by defining the fluid influx in the borehole.

Modeling Two-Phase Flowback of Multifractured Horizontal Wells Completed in Shale

SPE Journal ◽  
2013 ◽  
Vol 18 (04) ◽  
pp. 795-812 ◽  
Author(s):  
C.R.. R. Clarkson ◽  
J.D.. D. Williams-Kovacs
Keyword(s):  
Shale Gas ◽  
Transient Analysis ◽  
Horizontal Wells ◽  
Production Data ◽  
Two Phase ◽  
Fracture Properties ◽  
Rate Transient Analysis ◽  
Wellbore Storage ◽  
Fluid Production

Summary Early fluid production and flowing pressure data gathered immediately after fracture stimulation of multifractured horizontal wells may provide an early opportunity to generate long-term forecasts in shale-gas (and other hydraulically fractured) reservoirs. These early data, which often consist of hourly (if not more frequent) monitoring of fracture/formation fluid rates, volumes, and flowing pressures, are gathered on nearly every well that is completed. Additionally, fluid compositions may be monitored to determine the extent of load fluid recovery, and chemical tracers added during stage treatments to evaluate inflow from each of the stages. There is currently debate within the industry of the usefulness of these data for determining the long-term production performance of the wells. “Rules of thumb” derived from the percentage of load-fluid recovery are often used by the industry to provide a directional indication of well performance. More-quantitative analysis of the data is rarely performed; it is likely that the multiphase-flow nature of flowback and the possibility of early data being dominated by wellbore-storage effects have deterred many analysts. In this work, the use of short-term flowback data for quantitative analysis of induced-hydraulic-fracture properties is critically evaluated. For the first time, a method for analyzing water and gas production and flowing pressures associated with the flowback of shale-gas wells, to obtain hydraulic-fracture properties, is presented. Previous attempts have focused on single-phase analysis. Examples from the Marcellus shale are analyzed. The short (less than 48 hours) flowback periods were followed by long-term pressure buildups (approximately 1 month). Gas + water production data were analyzed with analytical simulation and rate-transient analysis methods designed for analyzing multiphase coalbed-methane (CBM) data. This analogy is used because two-phase flowback is assumed to be similar to simultaneous flow of gas and water during long-term production through the fracture system of coal. One interpretation is that the early flowback data correspond to wellbore + fracture volume depletion (storage). It is assumed that fracture-storage volume is much greater than wellbore storage. This flow regime appears consistent with what is interpreted from the long-term pressure-buildup data, and from the rate-transient analysis of flowback data. Assuming further that the complex fracture network created during stimulation is confined to a region around perforation clusters in each stage, one can see that fluid-production data can be analyzed with a two-phase tank-model simulator to determine fracture permeability and drainage area, the latter being interpreted to obtain an effective (producing) fracture half-length given geometrical considerations. Total fracture half-length, derived from rate-transient analysis of online (post-cleanup) data, verifies the flowback estimates. An analytical forecasting tool that accounts for multiple sequences of post-storage linear flow, followed by late-stage boundary flow, was developed to forecast production with flowback-derived parameters, volumetric inputs, matrix permeability, completion data, and operating constraints. The preliminary forecasts are in very good agreement with online production data after several months of production. The use of flowback data to generate early production forecasts is therefore encouraging, but needs to be tested for a greater data set for this shale play and for other plays, and should not be used for reserves forecasting.

Damage Tolerance of Well-Completion and Stimulation Techniques in Coalbed Methane Reservoirs

2005 ◽  
Vol 127 (3) ◽  
pp. 248-256 ◽  
Author(s):  
Hossein Jahediesfanjani ◽  
Faruk Civan
Keyword(s):  
Coalbed Methane ◽  
Damage Tolerance ◽  
Horizontal Wells ◽  
Gas Production ◽  
Productivity Index ◽  
Dual Porosity ◽  
Formation Damage ◽  
Hydraulic Fractures ◽  
Well Completion ◽  
Reservoir Conditions

Coalbed methane (CBM) reservoirs are characterized as naturally fractured, dual porosity, low permeability, and water saturated gas reservoirs. Initially, the gas, water, and coal are at thermodynamic equilibrium under prevailing reservoir conditions. Dewatering is essential to promote gas production. This can be accomplished by suitable completion and stimulation techniques. This paper investigates the efficiency and performance of the openhole cavity, hydraulic fractures, frack and packs, and horizontal wells as potential completion methods which may reduce formation damage and increase the productivity in coalbed methane reservoirs. Considering the dual porosity nature of CBM reservoirs, numerical simulations have been carried out to determine the formation damage tolerance of each completion and stimulation approach. A new comparison parameter, named as the normalized productivity index Jnp(t) is defined as the ratio of the productivity index of a stimulated well to that of a nondamaged vertical well as a function of time. Typical scenarios have been considered to evaluate the CBM properties, including reservoir heterogeneity, anisotropy, and formation damage, for their effects on Jnp(t) over the production time. The results for each stimulation technique show that the value of Jnp(t) declines over the time of production with a rate which depends upon the applied technique and the prevailing reservoir conditions. The results also show that horizontal wells have the best performance if drilled orthogonal to the butt cleats. Long horizontal fractures improve reservoir productivity more than short vertical ones. Open-hole cavity completions outperform vertical fractures if the fracture conductivity is reduced by any damage process. When vertical permeability is much lower than horizontal permeability, production of vertical wells will improve while productivity of horizontal wells will decrease. Finally, pressure distribution of the reservoir under each scenario is strongly dependent upon the reservoir characteristics, including the hydraulic diffusivity of methane, and the porosity and permeability distributions in the reservoir.

Productivity and Drainage Area of Fractured Horizontal Wells in Tight Gas Reservoirs

2008 ◽  
Vol 11 (05) ◽  
pp. 902-911 ◽  
Author(s):  
Flavio Medeiros ◽  
Erdal Ozkan ◽  
Hossein Kazemi
Keyword(s):  
Horizontal Well ◽  
Oil And Gas ◽  
Horizontal Wells ◽  
Drainage Area ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Tight Gas ◽  
Natural Fractures ◽  
Tight Formations ◽  
Fractured Horizontal Wells

Summary This paper discusses the performance and productivity of fractured horizontal wells in heterogeneous, tight-gas formations. Production characteristics and flow regimes of unfractured and fractured horizontal wells are documented. The results show that if hydraulic fracturing affects stress distribution to create or rejuvenate natural fractures around the well, the productivity of the system is significantly increased. Unless there is significant contrast between the conductivities of the hydraulic and natural fractures, hydraulic fractures may not significantly contribute to the productivity. For extremely tight formations, the effective drainage area may be limited to the naturally fractured region around the well and the hydraulic fractures. It is also shown that very long transient flow periods govern the productivity and economics of fractured horizontal wells in tight formations. The results of this study are also applicable to oil production from fractured shale. Introduction Economic gas and oil production from low permeability reservoirs has been a challenge for the oil and gas industry. Because most of the high permeability reservoirs have been exploited and many low permeability reservoirs remain undeveloped, the latter have taken the industry attention recently. Particular attention has been given to tight-gas reservoirs with permeability in the range of micro-Darcies or below and to oil accumulation in fractured shale. Hydraulically fractured horizontal wells are the proven technology to produce oil and gas from tight formations. Hydraulic fractures reduce well drawndown, increase the productivity of horizontal wells by increasing the surface area in contact with formation, and provide high conductivity paths to the wellbore. Depending on in-situ stress orientation, hydraulic fractures can be parallel (longitudinal) or perpendicular (transverse) to horizontal well axis. Project economics in tight formations, however, depends strongly on well spacing and the number of hydraulic fractures required to drain the reservoir efficiently. Field evidence indicates that the drainage areas of fractured horizontal wells in tight formations may be limited to a rectangular region confining the horizontal well and the transverse hydraulic fractures. Also, there has been evidence that hydraulic fracturing in tight formations changes stresses in fracture drainage area, which could create or rejuvenate natural fractures in the near-vicinity of the horizontal well. This fracture network, which may be characterized as a dual-porosity system, may contribute significantly to improve productivity of the fractured horizontal well. Much work has been done (Soliman et al. 1990; Larsen and Hegre 1994; Temeng and Horne 1995; Raghavan et al. 1997; Wan and Aziz 1999; Al-Kobaisi et al. 2006) to investigate pressure-transient analysis and short- and long-term productivity of horizontal wells with single or multiple hydraulic fractures. The effect of a dual-porosity zone surrounding hydraulic fractures, however, has not been considered in the previous studies. The main objective of this study is to investigate the combined effects of a dual-porosity region and hydraulic fractures on the productivity of horizontal wells. The results presented in this work are based on a semianalytical model developed by Medeiros et al. (2006). The model was derived from the Green's function formulation of the solution for the diffusivity equation (Gringarten and Ramey, 1974, Ozkan and Raghavan, 1991a, 1991b) and has the capability to incorporate local heterogeneities. In this work, we use the semianalytical model to incorporate induced finite-conductivity fractures (transverse and longitudinal) along the horizontal well and naturally fractured zones around the hydraulically fractured horizontal well by using the dual-porosity idealization. We use the example data sets given in Tables 1 through 3 to consider different cases of horizontal wells with and without induced and natural fractures.

Mathematical Model for Rate Transient Analysis with Additional Interface Skin for Fractured Horizontal Well With Weak Fluid Supply

2021 ◽  
Author(s):  
Jiali Zhang ◽  
Xinwei Liao ◽  
Nai Cao
Keyword(s):  
Mathematical Model ◽  
Transient Analysis ◽  
Horizontal Wells ◽  
Tight Gas ◽  
Fracture Conductivity ◽  
Multi Stage ◽  
Rate Transient Analysis ◽  
Proposed Model ◽  
Fluid Supply ◽  
Fractured Horizontal Wells

Abstract This paper develops a mathematical model for rate transient analysis in multi-stage fractured horizontal wells with considering weak fluid supply. A new concept of additional skin factor is introduced in the proposed model to characterize the fluid supply. Then, the mathematical model are solved by using the perturbation transformation, point source integration method, Laplace transform, and numerical inversion, while the fracture flow equations are solved by fracture discretization and superposition principle. First, the flow regimes of multi-stage fractured horizontal wells with considering weak fluid supply are identified based on the rate transient behaviors, including wellbore storage and skin effect, bilinear flow, linear flow, pseudo-radial flow in the fractured zone, interface skin effect, pseudo-radial flow in the original zone, and boundary-dominated flow. The effect of additional interface skin makes the double logarithmic curve of production rate appear an abrupt "overlap". The results of the sensitivity study show that the abrupt "overlap" becomes more obvious with the increase of the fracture conductivity, fracture number, the stress sensitivity coefficient, especially the interface skin. Finally, the proposed mathematical model is used to perform a case study on the production data of actual tight-gas wells from the Ordos Basin. The interface skin factor, fracture half-length, fracture conductivity, and boundary radius are evaluated. Through the proposed model, the characteristics of weak fluid supply in tight gas reservoirs are fully understood.

scholarly journals Pressure-Transient Performances of Fractured Horizontal Wells in the Compartmentalized Heterogeneous Unconventional Reservoirs

Energies ◽  
2020 ◽  
Vol 13 (19) ◽  
pp. 5204
Author(s):  
Dongyan Fan ◽  
Hai Sun ◽  
Jun Yao ◽  
Hui Zeng ◽  
Xia Yan ◽  
...  
Keyword(s):  
Computational Cost ◽  
Length Distribution ◽  
Horizontal Wells ◽  
Dual Porosity ◽  
Hydraulic Fractures ◽  
Function Solution ◽  
Dual Porosity Model ◽  
Fractured Horizontal Wells ◽  
High Computational Cost ◽  
Porosity Model

In order to investigate pressure performance of multiple fractured horizontal wells (MFHWs) penetrating heterogeneous unconventional reservoir and avoid the high computational cost of numerical simulation, a semi-analytical model for MFHWs combining Green function solution and boundary element method has been obtained, where the reservoir is divided into different homogeneous substructures and coupled at interface boundaries by plane source function in a closed rectangular parallelepiped. Hydraulic fractures are assumed uniform flux and dual porosity model is used for natural fractures system. Then the model is validated by compared with analytical solution of MFHWs in a homogeneous reservoir and trilinear flow model, which shows that this model can achieve high accuracy even with a small interface discretization number, and it can consider the radial flow around each hydraulic fractures. Finally, the pressure responses with heterogeneous parameters of reservoirs are discussed including heterogeneous permeability, non-uniform block-length and fracture half-length distribution as well as dual porosity parameters like elastic storage ratio and crossflow ratio.

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