Transient Pressure Test Interpretation from Continuously and Discretely Fractured Reservoirs

2012 ◽  
Author(s):  
Fikri J. Kuchuk ◽  
Denis Biryukov
Keyword(s):  
Fractured Reservoirs ◽  
Test Interpretation ◽  
Transient Pressure ◽  
Pressure Test

scholarly journals An approximation of behind-casing hydraulic conductivity between layers from transient pressure analysis

DYNA ◽  
2019 ◽  
Vol 86 (210) ◽  
pp. 108-114
Author(s):  
Freddy Humberto Escobar ◽  
Angela María Palomino ◽  
Alfredo Ghisays Ruiz
Keyword(s):  
Hydraulic Conductivity ◽  
Transient Analysis ◽  
Test Interpretation ◽  
Well Test ◽  
Transient Pressure ◽  
Pressure Transient Analysis ◽  
Pressure Transient ◽  
Transient Pressure Analysis ◽  
Pressure Analysis

Flow behind the casing has normally been identified and quantified using production logging tools. Very few applications of pressure transient analysis, which is much cheaper, have been devoted to determining compromised cemented zones. In this work, a methodology for a well test interpretation for determining conductivity behind the casing is developed. It provided good results with synthetic examples.

Evaluation of Fractured Reservoirs

1969 ◽  
Vol 9 (01) ◽  
pp. 28-38 ◽  
Author(s):  
G.R. Pickett ◽  
E.B. Reynolds
Keyword(s):  
Fluid Flow ◽  
Fractured Reservoirs ◽  
Fractured Reservoir ◽  
Flow Data ◽  
Fracture Detection ◽  
Transient Pressure ◽  
Variable Intensity ◽  
Reservoir Volume ◽  
Fracture Systems ◽  
Different Sources

Abstract Efforts were made to find improved means for locating fractures penetrated by a wellbore and for estimating fracture reservoir volume. The four approaches to the problem utilized acoustic logs, porosity estimates from different sources, transient pressure and fluid flow data, and resistivity logs. Acoustic amplitude attenuation and acoustic variable-intensity interference patterns have been used to locate fractures. Although amplitude logs have often proved useful for fracture detection, they are frequently inconclusive when used alone. This is due partially to variations in amplitude caused by factors other than fracturing. The variable-intensity interference patterns produced by borehole discontinuities in casing and in open-hole fractured sections were found to be quite useful in detecting fractures; but, like amplitude logs, they are not definitive by themselves. A technique has been developed that uses porosity estimate comparisons to evaluate fractured reservoirs. If this technique is used with acoustic variable-intensity interference patterns, it may be helpful for delineating fractured zones and for estimating fracture porosity. Transient pressure behavior observed for a fractured reservoir was found to be in agreement with that theoretically predicted for linear flow systems. Since this behavior is markedly different from that of a homogeneous reservoir, interpretation of transient pressures may provide a means of recognizing fractures. Other helpful techniques employing pressure and fluid flow data are comparison of calculated kh's for injection and withdrawal of fluids, comparison of calculated kh's for different rates of injection, and calculation of k/phi's from pressure and log data, where k is permeability, h is producing thickness, and phi is porosity. Some of these techniques also present possibilities for calculation of reservoir volumes. The fourth approach to fracture detection showed that, under certain conditions, an induction log can be used to detect a resistivity anomaly opposite a fractured zone. Although some of the techniques discussed show promise of being helpful, further study will be required before evaluations of fractured reservoirs become as satisfactory as evaluations of "normal" porosity reservoirs. Introduction Experience has shown that the presence of a fractured system can improve the productivity of hydrocarbon reservoirs. In some cases, fracture void space also supplies a significant portion of the total porosity. However, quantitative determination of the contribution of fracture systems to production from petroleum reservoirs has proven difficult. This is due in part to lack of consistently successful techniques for locating and usefully describing fracture systems penetrated by a wellbore. This paper presents the initial results of a research program on the use of borehole measurements for evaluation of fractured reservoirs. The objectives of this research are to find improved means forlocating fractures penetrated by a wellbore, andestimating in-situ reservoir volume contained within fracture systems in communication with the wellbore. This progress report will describe our attempts to date to use four types of data for fractured reservoir evaluation:acoustic logs,porosity estimates from different sources,transient pressure and fluid flow data, andresistivity logs. ACOUSTIC LOGS Amplitude Logs The acoustic amplitude log is one of the most widely used measurements in attempts to detect fractures. SPEJ P. 28ˆ

Condensate Bank Characterization from Well Test Data and Fluid PVT Properties

2006 ◽  
Vol 9 (05) ◽  
pp. 596-611 ◽  
Author(s):  
Manijeh Bozorgzadeh ◽  
Alain C. Gringarten
Keyword(s):  
Capillary Number ◽  
Gas Condensate ◽  
Test Interpretation ◽  
Well Test ◽  
Transient Pressure ◽  
Compositional Simulation ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Inertia Effects ◽  
The North

Summary Published well-test analyses in gas/condensate reservoirs in which the pressure has dropped below the dewpoint are usually based on a two- or three-region radial composite well-test interpretation model to represent condensate dropout around the wellbore and initial gas in place away from the well. Gas/condensate-specific results from well-test analysis are the mobility and storativity ratios between the regions and the condensate-bank radius. For a given region, however, well-test analysis cannot uncouple the storativity ratio from the region radius, and the storativity ratio must be estimated independently to obtain the correct bank radius. In most cases, the storativity ratio is calculated incorrectly, which explains why condensate bank radii from well-test analysis often differ greatly from those obtained by numerical compositional simulation. In this study, a new method is introduced to estimate the storativity ratios between the different zones from buildup data when the saturation profile does not change during the buildup. Application of the method is illustrated with the analysis of a transient-pressure test in a gas/condensate field in the North Sea. The analysis uses single-phase pseudo pressures and two- and three-zone radial composite well-test interpretation models to yield the condensate-bank radius. The calculated condensate-bank radius is validated by verifying analytical well-test analyses with compositional simulations that include capillary number and inertia effects. Introduction and Background When the bottomhole flowing pressure falls below the dewpoint in a gas/condensate reservoir, retrograde condensation occurs, and a bank of condensate builds up around the producing well. This process creates concentric zones with different liquid saturations around the well (Fevang and Whitson 1996; Kniazeff and Nvaille 1965; Economides et al. 1987). The zone away from the well, where the reservoir pressure is still above the dewpoint, contains the original gas. The condensate bank around the wellbore contains two phases, reservoir gas and liquid condensate, and has a reduced gas mobility, except in the immediate vicinity of the well at high production rates, where the relative permeability to gas is greater than in the bank because of capillary number effects (Danesh et al. 1994; Boom et al. 1995; Henderson et al. 1998; Mott et al. 1999).

Effect of Scaleup and Aggregation on the Use of Well Tests To Identify Geological Properties

2005 ◽  
Vol 8 (03) ◽  
pp. 248-254 ◽  
Author(s):  
Olubusola O. Thomas ◽  
Rajagopal S. Raghavan ◽  
Thomas N. Dixon
Keyword(s):  
History Matching ◽  
Small Scale ◽  
Well Test ◽  
Transient Pressure ◽  
Fine Grid ◽  
Pressure Transient ◽  
Number Of Layers ◽  
Pressure Test ◽  
Well Tests ◽  
The Impact

Summary This paper discusses specific issues encountered when pressure tests are analyzed in reservoirs with complex geological properties. These issues relate to questions concerning the methodology of scaleup, the degree of aggregation, and the reliability of conventional methods of analysis. The paper shows that if we desire to use pressure-transient analysis to determine more complex geological features such as connectivity and widths of channels, we need a model that incorporates reservoir heterogeneity. This complexity can lead to significantly more computational effort in the analysis of the pressure transient. The paper demonstrates that scaleup criteria, based on steady-state procedures, are inadequate to capture transient pressure responses. Furthermore, the number of layers needed to match the transient response may be significantly greater than the number of layers needed for a reservoir-simulation study. The use of models without a sufficient number of layers may lead to interpretations that are in significant error. The paper compares various vertical aggregation methods to coarsen the fine-grid model. The pressure-derivative curve is used as a measure of evaluating the adequacy of the scaleup procedure. Neither the use of permeability at a wellbore nor the average layer permeability as criteria for the aggregation was adequate to reduce the number of layers significantly. Introduction The objectives of this paper are to demonstrate the impact of the detailed and small-scale heterogeneities of a formation on the flow characteristics that are obtained from a pressure test and how those heterogeneities affect the analysis of the pressure test. The literature recognizes that special scaleup procedures are required in the vicinity of wells located in heterogeneous fields. Our work demonstrates that these procedures apply only to rather small changes in pressure over time and are usually inadequate to meet objectives for history-matching well tests. Using a fine-scale geological model derived by geological and geophysical techniques, this work systematically examines the interpretations obtained by various aggregation and scaleup techniques. We will demonstrate that unless care is taken, the consequences of too much aggregation may lead to significant errors on decisions concerning the value of a reservoir. Current scaleup techniques presume that spatial (location of boundaries, location of faults, etc.) variables are maintained. In analyzing a well test, however, one of our principal objectives is to determine the relationship between the well response and geometrical variables. We show that a limited amount of aggregation will preserve the spatial and petrophysical relationships we wish to determine. At this time, there appears to be no method available to determine the degree of scaleup a priori. Because the objective of well testing is to estimate reservoir properties, the scaleup process needs to be made a part of the history-matching procedure. By assuming a truth case, we show that too much vertical aggregation may lead to significant errors. Comparisons with traditional analyses based on analytical techniques are made. Whenever an analytical model is used in the analysis, unless otherwise stated, we use a single-layer-reservoir solution.

Swabbing-Test Interpretation Using Nonlinear Regression in San Jorge Gulf Basin

2010 ◽  
Vol 13 (04) ◽  
pp. 596-602
Author(s):  
Euver Naranjo ◽  
José Bravo ◽  
Eugenio Díaz ◽  
José Caldera
Keyword(s):  
Dynamic Properties ◽  
Test Interpretation ◽  
Transient Pressure ◽  
Individual Layer ◽  
Well Completion ◽  
Reservoir Permeability ◽  
Production Models ◽  
Routine Basis ◽  
Instantaneous Flow Rate ◽  
First Time

Summary In the San Jorge basin in southern Argentina, swabbing tests are the conventional testing technique used by YPF to evaluate production potential on those reservoirs that do not flow naturally to surface. During the well-completion phase, a swabbing device is lowered into the wellbore to test each reservoir layer individually. These wells, which produce from multilayer formations, are later completed for commingled production. Accordingly, the swabbing test represents the only opportunity to measure dynamic properties for each individual layer. So far, pressure-transient analysis of such tests has been limited to the use of conventional interpretation methods applied to the infinite-acting radial-flow (IARF) portion on those tests in which such a flow regime is observed. This can happen if a bottomhole shut-in valve is used or if the shut-in period is given a long enough time for the bottomhole pressure to reach conditions close to initial reservoir pressure. Unfortunately, both practices increase the completion cost substantially, which affects well economics strongly. As a result of this economic limitation, neither practice is applied on a routine basis, so most of the time, transient-pressure interpretation is not performed. In an attempt to obtain value from routine swabbing tests, where an IARF condition is not observed, a different method of test interpretation has been introduced. Through the computation of the instantaneous flow rate from the pressure-trend increase during the swabbing period, it is possible to use nonlinear numerical regression to make an estimation of the reservoir permeability, even if IARF is not present. With this innovative approach, YPF is constructing for the first time representative production models for each well, thereby improving reserves estimations and production forecasts.

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