Combining Step Rate Well Test With Transient-Pressure Test: Is It Possible?

2009 ◽  
Author(s):  
Dmitriy Borisovich Silin ◽  
George Jack Robin
Keyword(s):  
Well Test ◽  
Transient Pressure ◽  
Step Rate ◽  
Pressure Test

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.

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.

Properties of a Natural Fracture and Its Skins From Reservoir Well Tests

SPE Journal ◽  
2013 ◽  
Vol 19 (03) ◽  
pp. 390-397 ◽  
Author(s):  
M.. Prats ◽  
R.. Raghavan
Keyword(s):  
History Matching ◽  
Flow Resistance ◽  
Short Interval ◽  
Natural Fracture ◽  
Disperse Flow ◽  
Well Test ◽  
Transient Pressure ◽  
Matrix Permeability ◽  
Wide Range ◽  
Well Tests

Summary Two well tests are described that are aimed at the in-situ determination of the flow capacity (permeability-thickness product) of a natural fracture and the flow resistance of its skins at the boundaries with the reservoir matrix. Fracture skins tend to disperse flow, thus affecting the distribution of tracers in reservoir tests and contaminants and trace elements in aquifers. We are unaware of any other analytical procedure aimed at obtaining the properties of a natural fracture and its skins from subsurface measurements. Neither well test has been implemented. The well tests are modeled after previously reported analytical expressions for the transient pressure distributions in a three-region composite reservoir in a uniform-thickness reservoir in which (1) the natural fracture is represented by a thin middle region of relatively high permeability, (2) the pressure disturbance is caused by producing from a short interval in one of the outer regions, and (3) the response is measured relatively near the fracture. The source and sensor may be on the same side or on opposite sides of the fracture, distinguishing the two tests. Visualizing special completions in a horizontal well intersecting a natural fracture normally, pressure responses are given for both tests for a wide range of fracture/matrix permeability ratios and skin flow resistances for a source 190 ft from the fracture and 10 ft from the sensor and on either side of the fracture, both at the midplane of the reservoir. A simple graphical procedure, not intended to replace history matching or regression where field data are available, illustrates how the two unknowns—permeability-thickness product of a natural fracture and the flow resistance of its skins—may be estimated from two representative values of an assumed measured pressure response.

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).

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>

scholarly journals An Integrated Approach of Numerical Well Test for Well Intersecting Fractures Based on FMI Image

Lithosphere ◽  
2022 ◽  
Vol 2022 (Special 1) ◽  
Author(s):  
Guodong Jin ◽  
Huilin Xing ◽  
Tianbin Li ◽  
Rongxin Zhang ◽  
Junbiao Liu ◽  
...  
Keyword(s):  
Numerical Simulation ◽  
Radial Flow ◽  
Flow Characteristics ◽  
Integrated Approach ◽  
Unconventional Reservoirs ◽  
Well Test ◽  
Unconventional Reservoir ◽  
Transient Pressure ◽  
Drill Stem ◽  
Numerical Well Test

Abstract Fluid flow is strongly affected by fractures in unconventional reservoirs. It is essential to deeply understand the flow characteristics with fractures for improving the production and efficiency of unconventional reservoir exploitation. The purpose of this work is to develop an accurate numerical model to evaluate the transient-pressure response for well intersecting fractures. The meshes generated from Fullbore Formation Micro-Imager (FMI) images ensure an efficient numerical description of the geometries for fractures and interlayers. The numerical simulation is implemented by an inhouse finite element method-based code and benchmarked with drill stem test (DST) data. The results show that three flow regimes appear in the reservoir with fractures within the test period: wellbore afterflow, pseudolinear flow, and radial flow. In contrast, only the wellbore afterflow and radial flow appear for the wells without fractures. The results also reveal that fractures dominate the flow near the wellbore. Verification and application of the model show the practicability of the integrated approach for investigating the transient-pressure behaviors in the unconventional reservoir.

scholarly journals A mathematical model and semi-analytical solution for transient pressure of vertical fracture with varying conductivity in three crossflow rectangular layers

2018 ◽  
Vol 37 (1) ◽  
pp. 230-250 ◽  
Author(s):  
Jie Liu ◽  
Pengcheng Liu ◽  
Shunming Li ◽  
Xiaodong Wang
Keyword(s):  
Mathematical Model ◽  
Analytical Solution ◽  
Flow Characteristics ◽  
Well Test ◽  
Transient Pressure ◽  
Well Test Analysis ◽  
Test Analysis ◽  
Fracture Conductivity ◽  
Vertical Fracture ◽  
Flow Phase

This paper first describes a mathematical model of a vertical fracture with constant conductivity in three crossflow rectangular layers. Then, three forms of vertical fracture (linear, logarithmic, and exponential variations) with varying conductivity are introduced to this mathematical model. A novel mathematical model and its semi-analytical solution of a vertical fracture with varying conductivity intercepting a three-separate-layered crossflow reservoir is developed and executed. Results show that the transient pressures are divided into three stages: the linear-flow phase, the medium unsteady-flow stage, and the later pseudo-steady-flow phase. The parameters of the fracture, reservoir, and the multi-permeability medium directly influence the direction, transition, and shape of the transient pressure. Meanwhile, the fracture conductivity is higher near the well bottom and is smaller at the tip of the fracture for the varying conductivity. Therefore, there are many more differences between varying conductivity and constant conductivity. Varying conductivity can correctly reflect the flow characteristics of a vertical fractured well during well-test analysis.

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