A Digital Pressure Derivative Technique for Pressure Transient Well Testing and Reservoir Characterization

2006 ◽  
Author(s):  
Anthony Frank Veneruso ◽  
Jeffrey Bernard Spath
Keyword(s):  
Reservoir Characterization ◽  
Well Testing ◽  
Pressure Derivative ◽  
Pressure Transient ◽  
Digital Pressure ◽  
Pressure Transient Well Testing

scholarly journals Pressure and pressure derivative analysis for non-newtonian pseudoplastic fluids in double-porosity formations

2011 ◽  
Vol 4 (3) ◽  
pp. 47-60 ◽  
Author(s):  
Freddy-Humberto Escobar ◽  
Angela-Patricia Zambrano ◽  
Diana-Vanessa Giraldo ◽  
José-Humberto Cantillo
Keyword(s):  
Oil Recovery ◽  
Reservoir Characterization ◽  
Numerical Models ◽  
Simulated Data ◽  
Newtonian Fluids ◽  
Well Testing ◽  
Well Test ◽  
Well Test Analysis ◽  
Pressure Derivative ◽  
Derivative Analysis

Non-Newtonian fluids are often used during various drilling, workover and enhanced oil recovery processes. Most of the fracturing fluids injected into reservoir-bearing formations possess non-Newtonian nature and these fluids are often approximated by Newtonian fluid flow models. In the field of well testing, several analytical and numerical models taking into account Bingham, pseudoplastic and dilatant non-Newtonian behavior have been introduced in the literature to study their transient nature in porous media for a better reservoir characterization. Most of them deal with fracture wells and homogeneous formations and well test interpretation is conducted via the straight-line conventional analysis or type-curve matching. Only a few studies consider the pressure derivative analysis. However, there exists a need of a more practical and accurate way of characterizing such systems. So far, it does not exist any methodology to characterize heterogeneous formation bearing non-Newtonian fluids through of well test analysis.  In this study, an interpretation methodology using the pressure and pressure derivative log-log plot is presented for non-Newtonian fluids in naturally fractured formations, so the dimensionless fracture storativity ratio, ω, and interporosity flow parameter, λ, are obtained from characteristics points found on such plot. The developed equations and correlations are successfully verified by their application only to synthetic well test data since no actual field data are available. A good match is found between the results provided by the proposed technique and the values used to generate the simulated data.  

Application of Fractional Calculus in Reservoir Characterization From Pressure Transient Data in Fractal Reservoir With Phase Redistribution

2009 ◽  
Author(s):  
Asha S. Mishra
Keyword(s):  
Fractional Calculus ◽  
Reservoir Characterization ◽  
Dynamic Pressure ◽  
Fracture Network ◽  
Vital Role ◽  
Second Derivative ◽  
Reservoir Properties ◽  
Pressure Derivative ◽  
Pressure Transient ◽  
Vertical Permeability

The present paper describes the use of pressure derivative and second derivative of integral of pressure in a fractal reservoir with matrix participation with phase redistribution in a geological environment that are not possible by conventional techniques. The analysis of this type of data in reservoir characterization is known as “inverse problem” and one can obtain information about interwell and vertical permeability distribution in a reservoir. The fractal geometry in a dynamic pressure transient tests data plays a very vital role for heterogeneity characterization. The pressure transient response is analyzed for flow in a connected fracture network and fracture with matrix participation. The computer aided matching technique for both pressure and its derivative by nonlinear regression techniques are used in estimating the reservoir properties from measured drawdown/buildup and falloff pressure data of heterogeneous reservoir. In the present paper the fractional calculus approach has been utilized to solve the diffusivity equation with phase redistribution in fractal reservoir. The pressure solution of the diffusivity is in terms of Laplace space and its analytical inversion is not possible. We have obtained numerically inversion of the problem and the pressure, pressure derivative, integral of pressure and its first and second derivative has been calculated. The permeability estimated from pressure transient test data of a well are in good agreement with the identified the geological model.

Interpretation of Permanent Well Monitoring Data to Improve Characterization of a Giant Oil Field

2021 ◽  
Author(s):  
Hans Christian Walker ◽  
Anton Shchipanov ◽  
Harald Selseng
Keyword(s):  
Reservoir Characterization ◽  
Time Lapse ◽  
Interference Analysis ◽  
Pressure Transient ◽  
Pressure Transients ◽  
Reservoir Simulations ◽  
Production History ◽  
Fault Leakage ◽  
Fit For Purpose

Abstract The Johan Sverdrup field located on the Norwegian Continental Shelf (NCS) started its production in October 2019. The field is considered as a pivotal development in the view of sustainable long-term production and developments on the NCS as well as creating jobs and revenue. The field is operated with advanced well and reservoir surveillance systems including Permanent Downhole Gauges (PDG), Multi-Phase Flow-Meters (MPFM) and seismic Permanent Reservoir Monitoring (PRM). This provides an exceptional basis for reservoir characterization and permanent monitoring. This study focuses on reservoir characterization to improve evaluations of sand permeability-thickness and fault transmissibility. Permanent monitoring of the reservoir with PDG / MPFM has provided an excellent basis for applying different methods of Pressure Transient Analysis (PTA) including analysis of well interference and time-lapse PTA. Interpretation of pressure transient data is today based on both analytical and numerical reservoir simulations (fit-for-purpose models). In this study, such models of the Johan Sverdrup reservoir regions have been assembled, using geological and PVT data, results of seismic interpretations and laboratory experiments. Uncertainties in these data were used to guide and frame the scope of the study. The interference analysis has confirmed communication between the wells located in the same and different reservoir regions, thus revealing hydraulic communication through faults. Sensitivities using segment reservoir simulations of the interference tests with different number of wells have shown the importance of including all the active wells, otherwise the interpretation may give biased results. The estimates for sand permeability-thickness as well as fault leakage obtained from the interference analysis were further applied in simulations of the production history using the fit-for-purpose reservoir models. The production history contains many pressure transients associated with both flowing and shut-in periods. Time-lapse PTA was focused on extraction and history matching of these pressure transients. The simulations have provided reasonable match of the production history and the time-lapse pressure transients including derivatives. This has confirmed the results of the interference analysis for permeability-thickness and fault leakage used as input for these simulations. Well interference is also the dominating factor driving the pressure transient responses. Drainage area around the wells is quickly established for groups of the wells analyzed due to the extreme permeability of the reservoir. It was possible to match many transient responses with segment models, however mismatch for some wells can be explained by the disregard of wells outside the segments, especially injectors. At the same time, it is a useful indication of communication between the regions. The study has improved reservoir characterization of the Johan Sverdrup field, also contributing to field implementation of combined PTA methods.

A Comprehensive Model Integrating the Stress Sensitivity for Pressure Transient Behavior Study on the Two-Zone System for Offshore Loose Sandstone Reservoirs

2021 ◽  
Author(s):  
Chong Cao ◽  
Linsong Cheng ◽  
Xiangyang Zhang ◽  
Pin Jia ◽  
Wenpei Lu
Keyword(s):  
Flow Regimes ◽  
Transient Behavior ◽  
Stress Sensitivity ◽  
Composite Model ◽  
Zone Model ◽  
Well Testing ◽  
Comprehensive Model ◽  
Pressure Transient ◽  
Sandstone Reservoirs ◽  
Sandstone Formation

Abstract Permeability changes in the weakly consolidated sandstone formation, caused by sand migration, has a serious impact on the interpretation of well testing and production prediction. In this article, a two-zone comprehensive model is presented to describe the changes in permeability by integrating the produced sand, stress sensitivity characteristics. In this model, inner zone is modeled as a higher permeability radial reservoir because of the sand migration, while the outer zone is considered as a lower permeability reservoir. Besides, non-Newtonian fluid flow characteristics are considered as threshold pressure gradient in this paper. As a result, this bi-zone comprehensive model is built. The analytical solution to this composite model can be obtained using Laplace transformation, orthogonal transformation, and then the bottomhole pressure in real space can be solved by Stehfest and perturbation inversion techniques. Based on the oilfield cases validated in the oilfield data from the produced sand horizontal well, the flow regimes analysis shows seven flow regimes can be divided in this bi-zone model considering stress sensitive. In addition, the proposed new model is validated by the compassion results of traditional method without the complex factors. Besides, the effect related parameters of stress sensitivity coefficient, skin factor, permeability ratio and sanding radius on the typical curves of well-testing are analyzed. This work introduces two-zone composite model to reflect the variations of permeability caused by the produced sand in the unconsolidated sandstone formation, which can produce great influence on pressure transient behavior. Besides, this paper can also provide a more accurate reference for reservoir engineers in well test interpretation of loose sandstone reservoirs.

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