scholarly journals Rate Decline Analysis for Limited-Entry Well in Abnormally High-Pressured Composite Naturally Fractured Gas Reservoirs

2019 ◽  
Vol 9 (9) ◽  
pp. 1821
Author(s):  
Mingtao Wu ◽  
Xiaodong Wang ◽  
Wenqi Zhao ◽  
Lun Zhao ◽  
Meng Sun ◽  
...  
Keyword(s):  
Production Rate ◽  
High Efficiency ◽  
Negative Impact ◽  
Gas Production ◽  
Production Performance ◽  
Gas Reservoirs ◽  
Naturally Fractured ◽  
Limited Entry ◽  
Permeability Anisotropy ◽  
Stress Dependent

Most naturally fractured gas reservoirs in China exhibit strongly heterogeneous, abnormally high-pressured and, stress-sensitive behaviors. In this work, a semianalytical solution is developed to study the production performance for limited-entry well in composite naturally fractured formations. The pressure-dependent porosity and permeability, anisotropy and limited-entry characteristics are taken into consideration. Furthermore, conventional Warren-Root model is amended to accommodate for permeability anisotropy. Laplace and finite Fourier cosine transforms are used to solve the diffusivity equations. The model is verified on the basis of previous literature’s results and data of a field example from Moxi gas field in Southwest China. Through the parameters sensitivity analysis, the effects of prevailing factors on production performance are investigated. Results indicate that a large inner region radius and high mobility ratio can improve gas production rate in the early stage, while they also lead to a drastic decline of production rate in the late stage. Large permeability stress-dependent coefficient and low penetrated interval both have a negative impact on production rate. With its high efficiency and simplicity, this proposed approach can serve as a convenient tool to evaluate the behavior of partially penetrated production well in abnormally high-pressured composite naturally fractured gas reservoirs.

scholarly journals Analysis of Gas Flow Behavior for Highly Deviated Wells in Naturally Fractured-Vuggy Carbonate Gas Reservoirs

2019 ◽  
Vol 2019 ◽  
pp. 1-13 ◽  
Author(s):  
Kongjie Wang ◽  
Lian Wang ◽  
Caspar Daniel Adenutsi ◽  
Zhiping Li ◽  
Sen Yang ◽  
...  
Keyword(s):  
High Efficiency ◽  
Flow Behavior ◽  
Production Performance ◽  
Gas Reservoirs ◽  
Gas Reservoir ◽  
Reservoir Development ◽  
Proposed Model ◽  
Naturally Fractured ◽  
Production Behavior ◽  
Deviated Wells

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.

scholarly journals Multiphysics coupling study of near-wellbore and reservoir models in ultra-deep natural gas reservoirs

2022 ◽  
Author(s):  
Pengda Cheng ◽  
Weijun Shen ◽  
Qingyan Xu ◽  
Xiaobing Lu ◽  
Chao Qian ◽  
...  
Keyword(s):  
Natural Gas ◽  
Pore Pressure ◽  
Production Rate ◽  
Gas Production ◽  
Permeability Evolution ◽  
Gas Reservoirs ◽  
Reservoir Properties ◽  
Gas Field ◽  
Natural Gas Reservoirs ◽  
Stress Dependent

AbstractUnderstanding the changes of the near-wellbore pore pressure associated with the reservoir depletion is greatly significant for the development of ultra-deep natural gas reservoirs. However, there is still a great challenge for the fluid flow and geomechanics in the reservoir depletion. In this study, a fully coupled model was developed to simulate the near-wellbore and reservoir physics caused by pore pressure in ultra-deep natural gas reservoirs. The stress-dependent porosity and permeability models as well as geomechanics deformation induced by pore pressure were considered in this model, and the COMSOL Multiphysics was used to implement and solve the problem. The numerical model was validated by the reservoir depletion from Dabei gas field in China, and the effects of reservoir properties and production parameters on gas production, near-wellbore pore pressure and permeability evolution were discussed. The results show that the gas production rate increases nonlinearly with the increase in porosity, permeability and Young’s modulus. The lower reservoir porosity will result in the greater near-wellbore pore pressure and the larger rock deformation. The permeability changes have little effect on geomechanics deformation while it affects greatly the gas production rate in the reservoir depletion. With the increase in the gas production rate, the near-wellbore pore pressure and permeability decrease rapidly and tend to balance with time. The reservoir rocks with higher deformation capacity will cause the greater near-wellbore pore pressure.

Geomechanical Response Induced by Multiphase (Gas/Water) Flow in the Mallik Hydrate Reservoir of Canada

SPE Journal ◽  
2021 ◽  
pp. 1-18
Author(s):  
Yingli Xia ◽  
Tianfu Xu ◽  
Yilong Yuan ◽  
Xin Xin ◽  
Huixing Zhu
Keyword(s):  
Shear Stress ◽  
Shear Failure ◽  
Energy Resource ◽  
Gas Production ◽  
Production Performance ◽  
Reservoir Model ◽  
Hydrate Reservoir ◽  
Maximum Subsidence ◽  
Permeability Anisotropy

Summary Natural gas hydrate (NGH) is regarded as an important alternative future energy resource. In recent years, a few short-term production tests have been successfully conducted with both permafrost and marine sediments. However, long-term hydrate production performance and the potential geomechanical problems are not very clear. According to the available geological data at the Mallik site, a more realistic hydrate reservoir model that considers the heterogeneity of porosity, permeability, and hydrate saturation was developed and validated by reproducing the field depressurization test. The coupled multiphase and heat flow and geomechanical response induced by depressurization were fully investigated for long-term gas production from the validated hydrate reservoir model. The results indicate that long-term gas production through depressurization from a vertically heterogeneous hydrate reservoir is technically feasible, but the production efficiency is generally modest, with the low average gas production rate of 4.93 × 103 ST m3/d (ST represents the standard conditions) over a 1-year period. The hydrate dissociation region is significantly affected by the reservoir heterogeneity and reveals a heterogeneous dissociation front in the reservoir. The depressurization production results in significant increase of shear stress and vertical compaction in the hydrate reservoir. The response of shear stress indicates that the potential region of sand migration is mainly in the sand-dominant layer during gas production from the hydraulically heterogeneous hydrate reservoir (e.g., sand layers interbedded with clay layers). The maximum subsidence is approximately 78 mm and occurred at the 72nd day, whereas the final subsidence is slowly dropped to 63 mm after 1-year of depressurization production. The vertical subsidence is greatly dependent on the elastic properties and the permeability anisotropy. In particular, the maximum subsidence increased by approximately 81% when the ratio of permeability anisotropy was set at 5:1. Furthermore, the potential shear failure in the hydrate reservoir is strongly correlated to the in-situ stress state. For the normal fault stress regime, the greater the initial horizontal stress is, the less likely the hydrate reservoir is to undergo shear failure during depressurization production.

scholarly journals The Evaluation and Sensitivity of Decline Curve Modelling

Energies ◽  
2020 ◽  
Vol 13 (11) ◽  
pp. 2765
Author(s):  
Prinisha Manda ◽  
Diakanua Nkazi
Keyword(s):  
Shale Gas ◽  
Goodness Of Fit ◽  
Accuracy Assessment ◽  
Gas Production ◽  
Production Performance ◽  
Logistic Growth ◽  
Gas Reservoirs ◽  
Shale Gas Reservoirs ◽  
Decline Curve ◽  
Exponential Decline

The development of prediction tools for production performance and the lifespan of shale gas reservoirs has been a focus for petroleum engineers. Several decline curve models have been developed and compared with data from shale gas production. To accurately forecast the estimated ultimate recovery for shale gas reservoirs, consistent and accurate decline curve modelling is required. In this paper, the current decline curve models are evaluated using the goodness of fit as a measure of accuracy with field data. The evaluation found that there are advantages in using the current DCA models; however, they also have limitations associated with them that have to be addressed. Based on the accuracy assessment conducted on the different models, it appears that the Stretched Exponential Decline Model (SEDM) and Logistic Growth Model (LGM), followed by the Extended Exponential Decline Model (EEDM), the Power Law Exponential Model (PLE), the Doung’s Model, and lastly, the Arps Hyperbolic Decline Model, provide the best fit with production data.

scholarly journals A Hybrid Model for Simulating Fracturing Fluid Flowback in Tight Sandstone Gas Wells considering a Three-Dimensional Discrete Fracture

Lithosphere ◽  
2021 ◽  
Vol 2021 (Special 4) ◽  
Author(s):  
Suran Wang ◽  
Yuhu Bai ◽  
Bingxiang Xu ◽  
Yanzun Li ◽  
Ling Chen ◽  
...  
Keyword(s):  
Production Rate ◽  
Two Phase Flow ◽  
Three Dimensional ◽  
Gas Production ◽  
Production Performance ◽  
Phase Flow ◽  
Fracture Permeability ◽  
Tight Sandstone ◽  
Two Phase ◽  
Discrete Fracture

Abstract Two-phase (gas+water) flow is quite common in tight sandstone gas reservoirs during flowback and early-time production periods. However, many analytical models are restricted to single-phase flow problems and three-dimensional fracture characteristics are seldom considered. Numerical simulations are good choices for this problem, but it is time consuming in gridding and simulating. This paper presents a comprehensive hybrid model to characterize two-phase flow behaviour and predict the production performance of a fractured tight gas well with a three-dimensional discrete fracture. In this approach, the hydraulic fracture is discretized into several panels and the transient flow equation is solved by the finite difference method numerically. A three-dimensional volumetric source function and superposition principle are deployed to capture the flow behaviour in the reservoir analytically. The transient responses are obtained by coupling the flow in the reservoir and three-dimensional discrete fracture dynamically. The accuracy and practicability of the proposed model are validated by the numerical simulation result. The results indicate that the proposed model is highly efficient and precise in simulating the gas/water two-phase flow and evaluating the early-time production performance of fractured tight sandstone gas wells considering a three-dimensional discrete fracture. The results also show that the gas production rate will be overestimated without considering the two-phase flow in the hydraulic fracture. In addition, the influences of fracture permeability, fracture half-length, and matrix permeability on production performance are significant. The gas production rate will be higher with larger fracture permeability at the early production period, but the production curves will merge after fracturing fluid flows back. A larger fracture half-length and matrix permeability can enhance the gas production rate.

scholarly journals Numerical Investigation on Gas Production Performance in Methane Hydrate of Multilateral Well under Depressurization in Krishna-Godavari Basin

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-19
Author(s):  
Xin Xin ◽  
Si Li ◽  
Tianfu Xu ◽  
Yilong Yuan
Keyword(s):  
Production Rate ◽  
Production Efficiency ◽  
Gas Production ◽  
Geometric Parameters ◽  
Production Performance ◽  
Production Volume ◽  
Hydrate Decomposition ◽  
Single Well ◽  
Influence Radius ◽  
Lateral Branches

Nature gas hydrate is a new kind of clean and potential resources. Depressurization is regarded as the most effective and promising hydrate production technology. One of the key points in improving the gas production effectiveness of depressurization is whether pressure gradient could transmit in strata effectively. Single well method is widely used in hydrate exploit which is circumscribed in expanding the range of hydrate decomposition. Consequently, the well structure and production strategy needs to be optimized for improving the gas recovery efficiency. The multilateral well technology is proposed for increasing the gas productivity of the reservoir greatly by increasing the multilateral branches. In this paper, we established a numerical simulation model based on the geological data NGHP-02-16 site in the KG basin to evaluate the gas production performance of the reservoir by depressurization. It mainly focuses on investigating the gas production performance of multilateral wells with different combinations of geometric parameters of multilateral branches, such as different dip angle, numbers, and spacing of lateral branches. The result shows that the multilateral well method can effectively increase the gas production rate with the water production rate increase slightly. The cumulative gas production volume of a single vertical well is about 2.85 × 10 6   m 3 , while it is of the multilateral well can reach 4.18 × 10 6   m 3 during a one-year production. The well interference, the effective influence radius of each multilateral branch, and the vertical depth of the lateral branch are the main factors which affect the gas production efficiency of the multilateral well. The optimization of the geometric parameters of lateral should consider not only the gas production efficiency but also the well interference between the lateral branches.

Liquid loading in wellbores and its effect on cleanup period and well productivity in tight gas sand reservoirs

2010 ◽  
Vol 50 (1) ◽  
pp. 559
Author(s):  
Hassan Bahrami ◽  
M Reza Rezaee ◽  
Vamegh Rasouli ◽  
Armin Hosseinian
Keyword(s):  
Numerical Simulation ◽  
Gas Production ◽  
Production Performance ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Liquid Loading ◽  
Performance Modelling ◽  
Well Productivity ◽  
Tight Gas Reservoirs ◽  
Tight Gas Reservoir

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore they might not flow gas to surface at optimum rates without advanced production improvement techniques. After well stimulation and fracturing operations, invaded liquids such as filtrate will flow from the reservoir into the wellbore, as gas is produced during well cleanup. In addition, there might be production of condensate with gas. The produced liquids when loaded and re-circulated downhole in wellbores, can significantly reduce the gas production rate and well productivity in tight gas formations. This paper presents assessments of tight gas reservoir productivity issues related to liquid loading in wellbores using numerical simulation of multiphase flow in deviated and horizontal wells. A field example of production logging in a horizontal well is used to verify reliability of the numerical simulation model outputs. Well production performance modelling is also performed to quantitatively evaluate water loading in a typical tight gas well, and test the water unloading techniques that can improve the well productivity. The results indicate the effect of downhole liquid loading on well productivity in tight gas reservoirs. It also shows how well cleanup is sped up with the improved well productivity when downhole circulating liquids are lifted using the proposed methods.

Analysis of Effective Porosity and Effective Permeability in Shale-Gas Reservoirs With Consideration of Gas Adsorption and Stress Effects

SPE Journal ◽  
2017 ◽  
Vol 22 (06) ◽  
pp. 1739-1759 ◽  
Author(s):  
Y.. Pang ◽  
M. Y. Soliman ◽  
H.. Deng ◽  
Hossein Emadi
Keyword(s):  
Pore Pressure ◽  
Shale Gas ◽  
Gas Adsorption ◽  
Effective Porosity ◽  
Gas Production ◽  
Gas Reservoirs ◽  
Adsorption Effect ◽  
Shale Gas Reservoirs ◽  
Porosity And Permeability ◽  
Stress Dependent

Summary Nanoscale porosity and permeability play important roles in the characterization of shale-gas reservoirs and predicting shale-gas-production behavior. The gas adsorption and stress effects are two crucial parameters that should be considered in shale rocks. Although stress-dependent porosity and permeability models have been introduced and applied to calculate effective porosity and permeability, the adsorption effect specified as pore volume (PV) occupied by adsorbate is not properly accounted. Generally, gas adsorption results in significant reduction of nanoscale porosity and permeability in shale-gas reservoirs because the PV is occupied by layers of adsorbed-gas molecules. In this paper, correlations of effective porosity and permeability with the consideration of combining effects of gas adsorption and stress are developed for shale. For the adsorption effect, methane-adsorption capacity of shale rocks is measured on five shale-core samples in the laboratory by use of the gravimetric method. Methane-adsorption capacity is evaluated through performing regression analysis on Gibbs adsorption data from experimental measurements by use of the modified Dubinin-Astakhov (D-A) equation (Sakurovs et al. 2007) under the supercritical condition, from which the density of adsorbate is found. In addition, the Gibbs adsorption data are converted to absolute adsorption data to determine the volume of adsorbate. Furthermore, the stress-dependent porosity and permeability are calculated by use of McKee correlations (McKee et al. 1988) with the experimentally measured constant pore compressibility by use of the nonadsorptive-gas-expansion method. The developed correlations illustrating the changes in porosity and permeability with pore pressure in shale are similar to those produced by the Shi and Durucan model (2005), which represents the decline of porosity and permeability with the increase of pore pressure in the coalbed. The tendency of porosity and permeability change is the inverse of the common stress-dependent regulation that porosity and permeability increase with the increase of pore pressure. Here, the gas-adsorption effect has a larger influence on PV than stress effect does, which is because more gas is attempting to adsorb on the surface of the matrix as pore pressure increases. Furthermore, the developed correlations are added into a numerical-simulation model at field scale, which successfully matches production data from a horizontal well with multistage hydraulic fractures in the Barnett Shale reservoir. The simulation results note that without considering the effect of PV occupied by adsorbed gas, characterization of reservoir properties and prediction of gas production by history matching cannot be performed reliably. The purpose of this study is to introduce a model to calculate the volume of the adsorbed phase through the adsorption isotherm and propose correlations of effective porosity and permeability in shale rocks, including the consideration of the effects of both gas adsorption and stress. In addition, practical application of the developed correlations to reservoir-simulation work might achieve an appropriate evaluation of effective porosity and permeability and provide an accurate estimation of gas production in shale-gas reservoirs.

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