Analysis of Pressure And Pressure Derivative With And Without Type-curve Matching-A Horizontal Well In Closed-boundary System

Jongkittinarukorn, Kittiphong; Tiab, Djebbar

doi:10.2118/96-53

Cited by 6 publications

(5 citation statements)

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“…This procedure for interpreting pressure tests, which is referred to as the Tiab's Direct Synthesis (TDS) technique offers several advantages over the conventional semilog analysis and type curve matching. It has been applied to over fifty different reservoir systems [11][12][13][14][15][16][17][18] , and hundreds of field cases.…”

Section: (B) Tds Techniquementioning

confidence: 99%

Fracture Porosity of Naturally Fractured Reservoirs

Tiab

Restrepo

Igbokoyi

2006

International Oil Conference and Exhibition in Mexico

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe storage capacity ratio, ω, measures the flow capacitance of the secondary porosity and the interporosity flow parameter, λ, is related to the heterogeneity scale of the system. Currently, both parameters λ and ω are obtained from well test data by using the conventional semilog analysis, type-curve matching or the TDS Technique. Warren and Root showed how the parameter ω can be obtained from semilog plots. However, no accurate equation is proposed in the literature for calculating fracture porosity. This paper presents an equation for the estimation of the λ parameter using semilog plots. A new equation for calculating the storage capacity ratio and fracture porosity from the pressure derivative is presented. The equations are applicable to both pressure buildup and pressure drawdown tests. The interpretation of these pressure tests follows closely the classification of naturally fractured reservoirs into four types, as suggested by Nelson 1 . The paper also discusses new procedures for interpreting pressure transient tests for three common cases: (a) the pressure test is too short to observe the early-time radial flow straight line and only the first straight line is observed, (b) the pressure test is long enough to observe the late-time radial flow straight line, but the first straight line is not observed due to inner boundary effects, such as wellbore storage and formation damage, and (c) Neither straight line is observed for the same reasons, but the trough on the pressure derivative is well defined. Analytical equations are derived in all three cases for calculating permeability, skin, storage capacity ratio and interporosity flow coefficient, without using type curve matching. In naturally fractured reservoirs, the matrix pore volume, therefore the matrix porosity is reduced as a result of large reservoir pressure drop due to oil production. This large pressure drop causes the fracture pore volume, therefore fracture porosity, to increase. This behavior is observed particularly in reservoir where matrix porosity is much greater than fracture porosity. Fractures in reservoirs are more vertically than horizontally oriented, and the stress axis on the formation is also essentially vertical. Under these conditions, when the reservoir pressure drops, the fractures do not suffer from the stress caused by the drop. Using these principles, a new method is introduced for calculating fracture porosity from the storage capacity ratio, without assuming the total matrix compressibility is equal to the total fracture compressibility.Several numerical examples are presented for illustration purposes.

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Section: (B) Tds Techniquementioning

confidence: 99%

Fracture Porosity of Naturally Fractured Reservoirs

Tiab

Restrepo

Igbokoyi

2006

International Oil Conference and Exhibition in Mexico

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“…Estimation of distance from vertical wells to multiple boundaries without type-curve matching was presented by Ispas and Tiab (1999) and Jongkittinarukorn and Tiab (1996a). Jongkittinarukorn and Tiab (1996b) and Al Rbeawi and Tiab (2011b) extended TDS technique for horizontal wells in closed-boundary systems and multi-boundary systems, respectively. Escobar et al (2014j) studied pressure behavior in wedge and T-shaped reservoirs.…”

Section: State-of-the-art On Tds Techniquementioning

confidence: 99%

“…Moving to naturally fractured double-porosity single-permeability formations some works can be cited. The first work on this field was provided by Engler and Tiab (1996a) for vertical wells, Engler and Tiab (1996b) for horizontal wells in homogeneous reservoirs and Engler and Tiab (1996c) for horizontal wells in naturally fractured formations. TDS technique for dual-permeability naturally formations were presented by Escobar et al (2012i) for vertical wells and Lu et al (2009cLu et al ( , 2015 for horizontal wells.…”

Section: State-of-the-art On Tds Techniquementioning

confidence: 99%

The power of TDS technique for well test interpretation: a short review

Escobar

Jongkittnarukorn

Hernández

2018

J Petrol Explor Prod Technol

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Either pressure-transient analysis or rate-transient analysis can be interpreted by four methods: (1) conventional straight-line analysis, (2) type-curve matching procedure, (3) ACMM (automatic computer modeling matching), and (4) TDS (Tiab's direct synthesis) technique. The first three methods have serious drawbacks and are commonly misused by engineers. It does not mean they are useless since they provide good results if used properly. For example, combination of (4), (1), and (3) are strongly recommended by the authors since type-curve matching are tedious and use trial-and-error procedures. ACMM is not only the most used method, but also the most risky methodology since the non-linear regression analysis used to match the pressure test with the model output leads to multiple solutions (none uniqueness of the solution). Moreover, some engineers employ it as an inverse problem when pretending to define the model by matching the data with any model. For those who do not know the way, any transportation means is good for. This is a very wrong alternative since engineers must choose the reservoir model and the ACMM helps to find out the solution. Type-curve matching is not only risky, but tedious and it fails to provide accurate results in short tests. Conventional analysis has no way of verification and some engineers confuse the flow regimes and draw the straight line on the wrong region leading to wrong interpretations. TDS technique may be the panacea to the above-mentioned problems since it uses direct analytical solutions with information coming from characteristic points found on the pressure and pressure derivative vs. time log-log plot on which the interpreter can better define flow regimes and verify results from different sources. In this paper we demonstrate the practicability and accuracy of TDS technique with some detailed examples and results are quite well. The intention of this paper is to encourage people the use of TDS technique and provide a state-of-the-art of it. Although not mentioned, TDS technique has been used by common well test interpretation software. The power of TDS is not only based upon the accuracy and capability verification, but also the possibility of artificially created non-existing flow regimes to further estimate/verify reservoir parameters. This means the best and only accurate option for short pressure test interpretations is TDS technique. Then, an engineer is welcome to use the output results with ACMM to obtain an accurate matching.

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“…This minimum takes place at the point where the second pressure derivative equals zero (t D ×P D ')' = 0. 11 can be rewritten as: (12) The dimensionless time is defined as: Where t inf = t min . Therefore, Eq.…”

Section: Interporosity Flow Coefficientmentioning

confidence: 99%

“…It has been applied to over fifty different reservoir systems [11][12][13][14][15][16][17][18] , and hundreds of field cases. This technique utilizes the characteristic intersection points, slopes, and beginning and ending times of various straight lines corresponding to flow regimes strictly from log-log plots of pressure and pressure derivative data.…”

Section: Examplementioning

confidence: 99%

Fracture Porosity From Pressure Transient Data

Tiab

Igbokoyi²,

Restrepo

2007

All Days

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TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractThe storage capacity ratio (ω) measures the flow capacitance of the secondary porosity and the interporosity flow parameter (λ) is related to the heterogeneity scale of the system. Currently, both parameters λ and ω are obtained from well test data by using the conventional semilog analysis, type-curve matching or the TDS Technique. Warren and Root showed how the parameter ω can be obtained from semilog plots. However, no accurate equation is proposed in the literature for calculating fracture porosity. This paper presents an equation for the estimation of the λ parameter using semilog plots. A new equation for calculating the interporosity flow parameter, the storage capacity ratio and fracture porosity from the coordinates of the minimum point of the trough on the pressure derivative is presented. The influence of the wellbore storage on the trough was investigated and a new equation was derived to correct the coordinates of the minimum point. The equations are applicable to both pressure buildup and pressure drawdown tests. The interpretation of these pressure tests follows closely, the classification of naturally fractured reservoirs into four types, as suggested by Nelson.The paper also discusses new procedures for interpreting pressure transient tests for three common cases: (a) the pressure test is too short to observe the early-time radial flow straight line and only the first straight line is observed, (b) the pressure test is long enough to observe the late-time radial flow straight line, but the first straight line is not observed due to inner boundary effects, such as wellbore storage and formation damage, and (c) Neither straight line is observed for the same reasons, but the trough on the pressure derivative is well defined. Analytical equations are derived in all three cases for calculating permeability, skin, storage capacity ratio and interporosity flow coefficient, without using type curve matching.In naturally fractured reservoirs, the matrix pore volume, therefore the matrix porosity, is reduced as a result of large reservoir pressure drop due to oil production. This large pressure drop causes the fracture pore volume, therefore fracture porosity, to increase. This behavior is observed particularly in reservoir where matrix porosity is much greater than fracture porosity. Fractures in reservoirs are more vertically than horizontally oriented, and the stress axis on the formation is also essentially vertical. Using these principles, a new method is introduced for calculating fracture porosity from the storage capacity ratio, without assuming the total matrix compressibility is equal to the total fracture compressibility.Several numerical examples are presented for illustration purposes.

show abstract

Analysis of Pressure And Pressure Derivative With And Without Type-curve Matching-A Horizontal Well In Closed-boundary System

Cited by 6 publications

References 0 publications

Fracture Porosity of Naturally Fractured Reservoirs

Fracture Porosity of Naturally Fractured Reservoirs

The power of TDS technique for well test interpretation: a short review

Fracture Porosity From Pressure Transient Data

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