Analysis of pressure and pressure derivative without type curve matching, 4. Naturally fractured reservoirs

Engler, Thomas W.; Tiab, Djebbar

doi:10.1016/0920-4105(95)00064-x

Cited by 52 publications

(35 citation statements)

References 6 publications

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“…Taking the logarithm of both sides of the above equation gives: (9) This expression also shows that a log-log plot of ( ) …”

Section: Natural-fracture Dominated Flowmentioning

confidence: 96%

Practical Interpretation of Pressure Tests of Hydraulically Fractured Wells in a Naturally Fractured Reservoir

Tiab¹,

Bettam²

2007

Proceedings of Latin American &Amp; Caribbean Petroleum Engineering Conference

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fax 01-972-952-9435. AbstractThe main objective of this paper is to present a practical interpretation of the pressure behavior of a hydraulically fractured vertical well located in a naturally fractured reservoir. The interpretation is based on analytical equations derived to determine permeability, fracture storage capacity ratio, interporosity flow coefficient, skin and wellbore storage from the pressure derivative plot without using type-curve matching technique. These parameters are obtained by making use of the characteristic lines and points found on the log-log plot of pressure and pressure derivative. The point of intersection of the straight lines corresponding to the different flow regimes are very useful in checking the parameters obtained from the slopes, when the pressure derivative curve is not smooth. The method of analysis is applicable to both drawdown and buildup tests in uniform flux, infinite conductivity or finite conductivity hydraulic fracture. A step-by-step procedure and Examples are included to illustrate the proposed technique.

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“…Taking the logarithm of both sides of the above equation gives: (9) This expression also shows that a log-log plot of ( ) …”

Section: Natural-fracture Dominated Flowmentioning

confidence: 96%

Practical Interpretation of Pressure Tests of Hydraulically Fractured Wells in a Naturally Fractured Reservoir

Tiab¹,

Bettam²

2007

Proceedings of Latin American &Amp; Caribbean Petroleum Engineering Conference

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“…Transient well test analysis methods, such as rate drawdown, interference, and pressure build-up tests, are developed for and applied in the petroleum and natural gas industry for both conventional reservoirs and coalbed methane reservoirs (Matthews and Russell 1967;Earlougher 1977;Dake 1978;Lee 1982;King et al 1986;Mohaghegh and Ertekin 1991;Kuchuk and Onur 2003;Engler and Tiab 1996;Nashawi 2008;Kuchuk and Onur 2003;Valvatne et al 2003;Escobar et al 2007;Sheng 2009). These techniques can assist in understanding the characteristics of the gob reservoir and the interaction of GGVs with the gob and mining environment.…”

Section: Challenges In Gob and Ggv Characterizationmentioning

confidence: 99%

Monte Carlo Simulation and Well Testing Applied in Evaluating Reservoir Properties in a Deforming Longwall Overburden

Karacan

Goodman

2010

Transp Porous Med

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During longwall mining, the intact strata start to deform and fracture as the mining face progresses. Gob gas ventholes (GGVs) are drilled from the surface over a longwall panel before mining to capture methane from the fractured zone. Due to fracturing and bedding-plane separations, reservoir properties change extensively. This poses a major problem for venthole designers and methane control engineers and may become a safety and health concern for underground work force due to unexpected methane emissions: it is difficult to predict the location of major strata separations and their temporal magnitudes to best locate the ventholes. Measurements obtained at different times during longwall mining may not be helpful for this purpose as strata deformation is a dynamic process and the results from different tests may not be lumped together to analyze the data collectively. This article uses a combination of Monte Carlo (MC) simulation and well testing methods to analyze multiple data sets obtained from a GGV at different longwall face locations. The aim was to determine the magnitude of average strata separation before conducting well test analyses to determine the properties of a deformed reservoir. MC simulation was used to process cross-correlated and uncertain data distributions obtained from measurements to generate a set of normally distributed values for each data type. These values were further used to project the amount of strata separation to the timing of well test. Finally, well-test analyses were used to interpret test data and to evaluate reservoir properties. h Net pay (m, ft) k Permeability (md, md) kh Flow capacity (md.m, md.ft) k/μ Mobility kh/μ Transmissivity P Pressure (kPa, psia) w Channel thickness (m, ft) q j jth flow rate (m 3 /d, bbl/d) q n nth flow rate (m 3 /d, bbl/d) r e External radius or radius of investigation (m, ft) r w Wellbore radius (m, ft) s Apparent skin factor t Time (h, h) t a Pseudo-time (h, h) t n nth flow period or superposition time Pseudo-pressure for gas (kPa 2 /Pa.s, psia 2 /cp)

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“…In the case of fractured networks, permeability shall be assumed to be parallel to the fracture planes as shown in Figure 4 Darcy's law across a fracture path can be written as: Equating 18 and 19, for q = q n , and solving for fracture permeability becomes: 12 12…”

Section: Fracture Permeabilitymentioning

confidence: 99%

“…3) From the coordinates of the minimum point on the trough of the pressure derivative curve and the radial flow regime (horizontal) line, the storage capacity ratio is obtained as 12 :…”

Section: Tiab's Direct Synthesis Technique (Tds)mentioning

confidence: 99%

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Effects of Stress on Fracture Properties of Naturally Fractured Reservoirs

Chacon¹,

Tiab²

2007

Proceedings of Latin American &Amp; Caribbean Petroleum Engineering Conference

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fax 01-972-952-9435. AbstractThis paper analyzes the effect of stress on the rock properties fracture and matrix compressibilities, fracture and matrix porosities, and permeability in naturally fractured reservoirs (NFRs).In NFRs, fluids are stored inside the matrix pore space and inside the fractures of the rock. The reservoir characterization parameter indicating the volumetric fraction of fluids deposited inside the fractures is the storage capacity ratio, which is function of the fracture and matrix porosity, and fracture and matrix total compressibilities. Due to the difficulty to obtain these values, in reservoir engineering computations such as pressure transient analysis and reservoir simulation, among others, it is generally assumed that the matrix and the fracture total compressibilities are equal. This induces a big uncertainty in the estimation of the storage capacity ratio and leads to a wrong estimation of the volume of fluids inside the fractured rock.Changes in pore pressure due to production or injection of fluids affect the effective reservoir in-situ stress. The mechanical behavior of the fractured rock and its effects on the rock properties permeability, porosity and compressibility in the matrix and fracture frames are analyzed using the elastic properties bulk modulus and normal compliance of the fracture. These properties can be obtained from petrophysical core analysis or multi-component seismic interpretation, and linked to pressure transient analysis through the storage capacity ratio equation. A step-by-step procedure of the analysis is presented and illustrated with an example for quantifying the effects of changes in effective stress on the fracture and matrix compressibilities.

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Analysis of pressure and pressure derivative without type curve matching, 4. Naturally fractured reservoirs

Cited by 52 publications

References 6 publications

Practical Interpretation of Pressure Tests of Hydraulically Fractured Wells in a Naturally Fractured Reservoir

Practical Interpretation of Pressure Tests of Hydraulically Fractured Wells in a Naturally Fractured Reservoir

Monte Carlo Simulation and Well Testing Applied in Evaluating Reservoir Properties in a Deforming Longwall Overburden

Effects of Stress on Fracture Properties of Naturally Fractured Reservoirs

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