Transient Pressure Behaviour Under Non- Darcy Flow, Formation Damage and Their Combined Effect for Dual Porosity Reservoirs

2009 ◽  
Vol 48 (07) ◽  
pp. 54-65 ◽  
Author(s):  
F. Zeng ◽  
G. Zhao ◽  
X. Xu
Keyword(s):  
Combined Effect ◽  
Darcy Flow ◽  
Dual Porosity ◽  
Formation Damage ◽  
Transient Pressure ◽  
Flow Formation

Combined Effect of Non-Darcy Flow and Formation Damage on Gas Well Performance of Dual-Porosity and Dual-Permeability Reservoirs

2006 ◽  
Vol 9 (05) ◽  
pp. 543-552 ◽  
Author(s):  
Carlos A. Pereira ◽  
Hossein Kazemi ◽  
Erdal Ozkan
Keyword(s):  
Fractured Reservoirs ◽  
Naturally Fractured Reservoirs ◽  
Combined Effect ◽  
Flow Coefficient ◽  
Darcy Flow ◽  
Dual Porosity ◽  
Formation Damage ◽  
Well Performance ◽  
Skin Damage ◽  
Naturally Fractured

Summary This paper addresses the combined effect of formation damage and non-Darcy flow in naturally fractured reservoirs using simplified analytical solutions and a 2D numerical simulator. Pressure drawdown, buildup, and isochronal tests simulated in this work indicate that, despite high fracture permeability, skin damage may accentuate the non-Darcy flow effect and drastically influence pressure-transient characteristics of low-pressure, naturally fractured reservoirs. In high-pressure reservoirs, this effect is significant only at high rates. Non-Darcy flow does not usually mask the typical pressure-transient characteristics of dual-porosity and dual-permeability reservoirs, but the conventional interpretation of the early-time data may lead to erroneous results. If the exponent, n, of the isochronal tests approaches 0.5 while the matrix permeability is low and flow rate is rather high, this would indicate the predominance of fracture flow. Under these conditions, small contributions from skin damage may greatly reduce gas-well performance in naturally fractured reservoirs. Introduction High velocity flow through porous media and fractures causes a higher pressure drop than predicted by the Darcy equation. This phenomenon, generally referred to as non-Darcy flow, was first described by Forchheimer (1901). Since then, it has been well established that the main variables that affect non-Darcy flow are the velocity, density, and saturation of the fluid and the permeability and porosity of the reservoir. Reservoir properties may be correlated to a single parameter, known as the non-Darcy flow coefficient, beta. Very little is known about the effect of other parameters, such as physical skin damage, on non-Darcy flow and their consequences in well performance. In fact, a recent literature review on non-Darcy flow by Li and Engler (2001a) indicates that most of the work has been focused on finding an accurate correlation for the non-Darcy flow coefficient, beta. There is also the issue of non-Darcy flow in dual-porosity and dual-permeability reservoirs, where high local velocities are prominent in the fractures. This paper pertains specifically to this issue. In general, the lower the formation permeability, the greater the non-Darcy pressure gradient. Formation damage in the near-wellbore region causes a drastic reduction in formation permeability, which potentially could be even more prominent in naturally fractured reservoirs. Thus, a greater non-Darcy flow effect could result in the wellbore region of a dual-porosity reservoir. The literature explaining the combined effect of physical damage and non-Darcy flow in single-porosity reservoirs is abundant (Berumen-C. et al. 1989; Camacho-V. et al. 1993; Fligelman et al. 1981); however, there is little information about such effects in dual-porosity and dual-permeability reservoirs. A finite-difference, 2D simulator in cylindrical coordinates was constructed to simulate pressure-drawdown and -buildup tests. By analyzing the simulated pressure drawdown and buildup tests, it was possible to decipher the combined effect of the skin damage and non-Darcy flow in fractured reservoirs. Both dual-porosity and dual-permeability idealizations of fractured reservoirs were considered.

A Semianalytical Model for Predicting Transient Pressure Behavior of a Hydraulically Fractured Horizontal Well in a Naturally Fractured Reservoir With Non-Darcy Flow and Stress-Sensitive Permeability Effects

SPE Journal ◽  
2019 ◽  
Vol 24 (03) ◽  
pp. 1322-1341 ◽  
Author(s):  
Liwu Jiang ◽  
Tongjing Liu ◽  
Daoyong Yang
Keyword(s):  
Mathematical Models ◽  
Horizontal Well ◽  
Flow Behavior ◽  
Stress Sensitivity ◽  
Darcy Flow ◽  
Combined Effects ◽  
Fractured Reservoir ◽  
Transient Pressure ◽  
Linear Flow ◽  
Fractured Horizontal Well

Summary Non-Darcy flow and the stress-sensitivity effect are two fundamental issues that have been widely investigated in transient pressure analysis for fractured wells. The main object of this work is to establish a semianalytical solution to quantify the combined effects of non-Darcy flow and stress sensitivity on the transient pressure behavior for a fractured horizontal well in a naturally fractured reservoir. More specifically, the Barree-Conway model is used to quantify the non-Darcy flow behavior in the hydraulic fractures (HFs), while the permeability modulus is incorporated into mathematical models to take into account the stress-sensitivity effect. In this way, the resulting nonlinearity of the mathematical models is weakened by using Pedrosa's transform formulation. Then a semianalytical method is applied to solve the coupled nonlinear mathematical models by discretizing each HF into small segments. Furthermore, the pressure response and its corresponding derivative type curve are generated to examine the combined effects of non-Darcy flow and stress sensitivity. In particular, stress sensitivity in HF and natural-fracture (NF) subsystems can be respectively analyzed, while the assumption of an equal stress-sensitivity coefficient in the two subsystems is no longer required. It is found that non-Darcy flow mainly affects the early stage bilinear and linear flow regime, leading to an increase in pressure drop and pressure derivative. The stress-sensitivity effect is found to play a significant role in those flow regimes beyond the compound-linear flow regime. The existence of non-Darcy flow makes the effect of stress sensitivity more remarkable, especially for the low-conductivity cases, while the stress sensitivity in fractures has a negligible influence on the early time period, which is dominated by non-Darcy flow behavior. Other parameters such as storage ratio and crossflow coefficient are also analyzed and discussed. It is found from field applications that the coupled model tends to obtain the most-reasonable matching results, and for that model there is an excellent agreement between the measured and simulated pressure response.

scholarly journals RESERVOIR CHARACTERIZATION USING PRESSURE DERIVATIVE METHOD IN NA-20 WELL SENJA FIELD

PETRO ◽  
2019 ◽  
Vol 7 (3) ◽  
pp. 131 ◽  
Author(s):  
Nadhira Andini ◽  
Muh Taufiq Fathaddin ◽  
Cahaya Rosyidan
Keyword(s):  
Quality Data ◽  
Formation Damage ◽  
Well Test ◽  
Transient Pressure ◽  
Well Test Analysis ◽  
Transient Time ◽  
Pressure Derivative ◽  
Straight Line ◽  
Short Period ◽  
Pressure Analysis

<p><em>Th</em><em>e pressure behaviour of a well can be easily measured and is useful in analysing and predicting reservoir performance or diagnosing the condition of a well. Since a well test and subsequent pressure transient analysis is the most powerful tool available to the reservoir engineer for determining reservoir characteristics, the subject of well test analysis has attracted considerable attention. A well test is the only method available to the reservoir engineer for examining the dynamic response in the reservoir and considerable information can be gained from a well test. A well test is the examination of the transient behaviour of a porous reservoir as the result of a temporary change in production conditions performed over a relatively short period of time in comparison to the producing life of field. The build up can be both the part of the test when the well is shut in and a value represented by the difference in the pressure measured at any time during the build up and the final flowing pressure. The most common megods of transient (time dependant) pressure analysis required that data points be selected such that they fell on a well-defined straight line on either semi-logarithmic or cartesian graph paper. The well test analyst must the insure that the proper straight line has been chosen if more than one line can be drawn through the plotted data. This aspect of interpretation of well test data requires the input of reservoir engineer. Equally important is the design of a well test to ensure that the duration and format of the test is such that it produces good quality data for analysis. The results obtained from transient pressure analysis are used to discover the formation damage by detemining skin. This experiment will be analyzed oil well which is NA-20 well in Senja field. The results from the analysis of the data obtained on NA-20 well is 4.84 mD permeability, skin +1.42, pressure changes due to skin (ΔPskin) 264.384 psi, and flow efficiency 0.842 with 851.61 ft radius of investigation. The result from the analysis of the well showed that NA-20 well in Senja field have formation damage.</em></p>

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.

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