scholarly journals Wellbore Effects in the Analysis of Two-Phase Geothermal Well Tests

1982 ◽  
Vol 22 (03) ◽  
pp. 309-320 ◽  
Author(s):  
Constance W. Miller ◽  
Sally M. Benson ◽  
Michael J. O'Sullivan ◽  
Karsten Pruess
Keyword(s):  
Water Reservoir ◽  
Hot Water ◽  
Well Test ◽  
Two Phase ◽  
Pressure Transient ◽  
Analysis Techniques ◽  
Wellbore Storage ◽  
Storage Effects ◽  
Transient Data ◽  
Well Tests

Abstract A method of designing and analyzing pressure transient well tests of two-phase (steam/water) reservoirs is given. Wellbore storage is taken into account, and the duration of it is estimated. It is shown that the wellbore flow can dominate the downhole pressure signal completely such that large changes in the downhole pressure that might be expected because of changes in kinematic mobility are not seen. Changes in the flowing enthalpy from the reservoir can interact with the wellbore flow so that a temporary plateau in the downhole transient curve is measured. Application of graphical and nongraphical methods to determine reservoir parameters from drawdown tests is demonstrated. Introduction Pressure transient data analysis is the most common method of obtaining estimates of the in-situ reservoir properties and the wellbore condition. Conventional graphical analysis techniques require that. for a constant flowrate well test in an infinite aquifer, a plot of the downhole pressure vs. log time yields a straight line after wellbore storage effects are over. The slope of that line is inversely proportional to the transmissivity (kh/u) of the reservoir. The extrapolated intercept of this line with the pressure axis at a specified time (1 hour or 1 second depending on the units used) gives the factor 0 Cth(re2), which is used to calculate the skin value of a well. In this study, the effects of a two-phase steam/water mixture in the reservoir and/or the wellbore on pressure transient data have been investigated. There have been a number of attempts to extend conventional testing and analysis techniques to two-phase geothermal reservoirs including drawdown analysis by Garg and Pritchett, Garg, Grant, and Moench and Atkinson. Pressure buildup analysis has been investigated by Sorey et al. To solve the diffusion equation that governs the pressure change in a two-phase reservoir analytically, it is necessary to make a number of simplifying assumptions. One assumption is that the fluid compressibility in the reservoir is initially uniform and remains uniform throughout the test. With this approach, it can be shown that a straight line on a pressure vs. log time plot will be obtained, the slope being inversely proportional to the total kinematic mobility When conducting a field test it is rarely possible to maintain the uniform saturation distribution in the reservoir required for that type of analysis to be applicable. In addition, the very high compressibility of the two-phase fluid creates wellbore storage of very long duration. Since most of the available instrumentation for hot geothermal wells (greater than 200C) can withstand geothermal environments for only limited periods, long-duration wellbore storage further complicates data analysis. Thus numerical simulation techniques must be used to study well tests to determine the best method of testing two-phase reservoirs. This work investigates and defines more thoroughly the well/reservoir system when the reservoir or wellbore is filled with a two-phase fluid. Four examples are considered:a single-phase hot water reservoir connected to a partially two-phase wellbore,a hot water reservoir that becomes two-phase during the test,a two-phase liquid-dominated reservoir, anda two-phase vapor-dominated reservoir. State-of-the-art analysis techniques are applied to pressure transient data after wellbore storage effects have ended. In the first example, a nongraphical method of analysis is discussed, which is applicable at early times when wellbore storage effects still dominate the pressure response. Note that our analysis has been done for a two-phase homogeneous, nonfractured reservoir. Previous studies of well test methods for two-phase reservoirs have been restricted to this case. SPEJ P. 309^

scholarly journals Explicit Deconvolution of Well Test Data Dominated by Wellbore Storage

2014 ◽  
Vol 2014 ◽  
pp. 1-12
Author(s):  
K. Razminia ◽  
A. Hashemi ◽  
A. Razminia ◽  
D. Baleanu
Keyword(s):  
Test Data ◽  
Material Balance ◽  
Early Time ◽  
Time Behavior ◽  
Well Test ◽  
Deconvolution Method ◽  
Pressure Data ◽  
Practical Applications ◽  
Wellbore Storage ◽  
Storage Effects

This paper addresses some methods for interpretation of oil and gas well test data distorted by wellbore storage effects. Using these techniques, we can deconvolve pressure and rate data from drawdown and buildup tests dominated by wellbore storage. Some of these methods have the advantage of deconvolving the pressure data without rate measurement. The two important methods that are applied in this study are an explicit deconvolution method and a modification of material balance deconvolution method. In cases with no rate measurements, we use a blind deconvolution method to restore the pressure response free of wellbore storage effects. Our techniques detect the afterflow/unloading rate function with explicit deconvolution of the observed pressure data. The presented techniques can unveil the early time behavior of a reservoir system masked by wellbore storage effects and thus provide powerful tools to improve pressure transient test interpretation. Each method has been validated using both synthetic data and field cases and each method should be considered valid for practical applications.

An Investigation of Wellbore Storage and Skin Effect in Unsteady Liquid Flow: I. Analytical Treatment

1970 ◽  
Vol 10 (03) ◽  
pp. 279-290 ◽  
Author(s):  
Ram G. Agarwal ◽  
Rafi Al-Hussainy ◽  
H.J. Ramey
Keyword(s):  
Skin Effect ◽  
Initial Period ◽  
Outer Boundary ◽  
Well Test ◽  
Time Data ◽  
Wellbore Storage ◽  
Straight Line ◽  
Pan American ◽  
Well Tests ◽  
Short Time

Agarwal, Ram G., Pan American Petroleum Corp. Tulsa, Okla., Pan American Petroleum Corp. Tulsa, Okla., Al-Hussainy, Rafi, Junior Members AIME, Mobil Research and Development Corp., Dallas, Tex., Ramey Jr., H.J., Member AIME, Stanford U. Stanford, Calif. Abstract Due to the cost of extended pressure-drawdownor buildup well tests and the possibility of acquisitionof additional information from well tests, the moderntrend has been toward development of well-testanalysis methods pertinent for short-time data."Short-time" data may be defined as pressureinformation obtained prior to the usual straight-lineportion of a well test. For some time there has been portion of a well test. For some time there has been a general belief that the factors affecting short-timedata are too complex for meaningful interpretations. Among these factors are wellbore storage, variousskin effects such as perforations, partial penetration, fractures of various types, the effect of a finiteformation thickness, and non-Darcy flow. A numberof recent publications have dealt with short-timewell-test analysis. The purpose of this paper isto present a fundamental study of the importance ofwellbore storage with a skin effect to short-timetransient flow. Results indicate that properinterpretations of short-time well-test data can bemade under favorable circumstances. Upon starting a test, well pressures appearcontrolled by wellbore storage entirely, and datacannot be interpreted to yield formation flowcapacity or skin effect. Data can be interpreted toyield the wellbore storage constant, however. Afteran initial period, a transition from wellbore storagecontrol to the usual straight line takes place. Dataobtained during this period can be interpreted toobtain formation flow capacity and skin effect incertain cases. One important result is that thesteady-state skin effect concept is invalid at veryshort times. Another important result is that thetime required to reach the usual straight line isnormally not affected significantly by a finite skineffect. Introduction Many practical factors favor short-duration welltesting. These include loss of revenue during shut-in, costs involved in measuring drawdown or buildupdata for extended periods, and limited availabilityof bottomhole-pressure bombs where it is necessaryto survey large numbers of wells. on the other hand, reservoir engineers are well aware of the desirabilityof running long-duration tests. The result is usuallya compromise, and not necessarily a satisfactoryone. This situation is a common dilemma for thefield engineers who must specify the details of specialwell tests and annual surveys, and interpret theresults. For this reason, much effort has been givento the analysis of short-time tests. The term"short-time" is used herein to indicate eitherdrawdown or buildup tests run for a period of timeinsufficient to reach the usual straight-line portions. Drawdown data taken before the traditional straight-lineportion are ever used in analysis of oil or gas portion are ever used in analysis of oil or gas well performance. Well files often contain well-testdata that were abandoned when it was realized thatthe straight line had not been reached. This situationis particularly odd when it is realized that earlydata are used commonly in other technologies whichemploy similar, or analogous, transient test. It is the objective of this study to investigatetechniques which may be used to interpret informationobtained form well tests at times prior to the normalstraight-line period. THEORY The problem to be considered is the classic oneof flow of a slightly compressible (small pressuregradients) fluid in an ideal radial flow system. Thatis, flow is perfectly radial to a well of radius rwin an isotropic medium, and gravitational forces areneglected. We will consider that the medium isinfinite in extent, since interest is focused on timesshort enough for outer boundary effects not to befelt at the well. SPEJ p. 279

scholarly journals A Two-Phase Numerical Model of Well Test Analysis to Characterize Formation Damage in Near-Well Regions of Injection Wells

Geofluids ◽  
2021 ◽  
Vol 2021 ◽  
pp. 1-15
Author(s):  
Jia Zhang ◽  
Shiqing Cheng ◽  
Shiying Di ◽  
Zhanwu Gao ◽  
Rui Yang ◽  
...  
Keyword(s):  
Flow Regimes ◽  
Transient Behavior ◽  
Formation Damage ◽  
Well Test ◽  
Well Test Analysis ◽  
Injection Wells ◽  
Two Phase ◽  
Test Analysis ◽  
Specific Flow ◽  
Pressure Transient

Formation damage usually occurs in near-well regions for injection wells completed in offshore oilfields under the development of line drive patterns. However, current works on characterizing the damage by well test analysis were basically focused on using single-phase analogy to solve two-phase flow issues, resulting in errors on the diagnosis and interpretation of transient pressure data. In this paper, we developed a two-phase model to simulate the pressure transient behavior of a water injection well in a multiwell system. To solve the model more efficiently, we used the finite volume method to discretize partially differential flow equations in a hybrid grid system, including both Cartesian and radial meshes. The fully implicit Newton-Raphson method was also employed to solve the equations in our model. With this methodology, we compared the resulting solutions with a commercial simulator. Our results keep a good agreement with the solutions from the simulator. We then graphed the solutions on a log-log plot and concluded that the effects of transitional zone and interwell interference can be individually identified by analyzing specific flow regimes on the plot. Further, seven scenarios were raised to understand the parameters which dominate the pressure transient behavior of these flow regimes. Finally, we showed a workflow and verified the applicability of our model by demonstrating a case study in a Chinese offshore oilfield. Our model provides a useful tool to reduce errors in the interpretation of pressure transient data derived from injection wells located in a line drive pattern.

Assimilating Microseismic and Well-Test Data by Use of EnKF for Accurate Reservoir Characterization

SPE Journal ◽  
2014 ◽  
Vol 20 (01) ◽  
pp. 186-201 ◽  
Author(s):  
Mei Han ◽  
Gaoming Li ◽  
Jingyi Chen
Keyword(s):  
Test Data ◽  
Reservoir Characterization ◽  
Weighted Average ◽  
Well Test ◽  
Sampling Errors ◽  
Reservoir Properties ◽  
Reservoir Prediction ◽  
Pressure Transient ◽  
Microseismic Data ◽  
Transient Data

Summary The pressure-transient well-test data can be used to determine the thickness-weighted average permeability in a multilayer reservoir. Injection- or production-profile logs (layer rates), if available, may be used to further quantify the layer properties. This paper explores the possibility of the use of microseismic data in place of injection-/production-profile logs for layered-reservoir characterization. The microseismic first-arrival times from the perforation-timing shots of the test well to monitor wells can only resolve the average velocity along its wavepath but are more sensitive to the layer (or region) with high wave velocity (low productivity). On the contrary, the pressure-transient data are more sensitive to the properties of the high-productivity (high-permeability) layers. Therefore, these two types of data are complementary in reservoir characterization. In this paper, we assimilate these two types of data by use of the state-of-the-art ensemble-Kalman-filter (EnKF) method. Layered-homogeneous- and layered-heterogeneous-reservoir examples verified the complementary nature of these two types of data. The porosities and permeabilities in the layered reservoir obtained after assimilating both types of data are comparable with assimilating pressure-transient and layer-rate data. EnKF is a stochastic process, and the final results may depend on the initial ensemble because of sampling errors, sample size, and nonlinearity of the problem. In this paper, we generated 10 different ensembles for each example for better uncertainty quantification. The paper shows that assimilating pressure-transient data only will yield biased estimates of layered-reservoir properties, whereas assimilating both pressure and microseismic data improves the reservoir-property estimation and reservoir-prediction capabilities.

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 Effects of Steam/Liquid Counterflow on Pressure-Transient Data From Two-Phase Geothermal Reservoirs

1989 ◽  
Vol 4 (02) ◽  
pp. 187-193
Author(s):  
Gudmundur Bodvarsson ◽  
B. Lea Cox ◽  
M. Ripperda
Keyword(s):  
Two Phase ◽  
Pressure Transient ◽  
Geothermal Reservoirs ◽  
Transient Data

A New Method to Identify and Quantify Hydraulic Communication between Isolated Reservoir Systems Using Pressure-Transient Data

2021 ◽  
Author(s):  
Hasan A. Nooruddin ◽  
N. M. Anisur Rahman
Keyword(s):  
Test Duration ◽  
Well Test ◽  
Pressure Transient ◽  
Type Curves ◽  
Unlimited Number ◽  
Communication Mechanism ◽  
Wide Range ◽  
Transient Data ◽  
New Formulation ◽  
The Impact

Abstract A new analytical workflow that uses pressure-transient data to characterize connectivity between two originally non-communicating reservoir zones is presented. With this technique, hydraulic communication is clearly identified and corresponding fluid crossflow rates accurately quantified. It is applicable to a wide range of communication mechanisms, including inactive commingled-completion wells, conductive fractures and faults, in addition to behind-casing completion problems. The impact of interference is also captured by handling an unlimited number of wells and communicating media. The solution uses pressure-transient data effectively to diagnose communication and estimate the amount of transported fluids. The new formulation is a general formulation for handling an unlimited number of producing wells and communicating media, which helps analyze pressure responses under the influence of interference. The reservoir system under consideration is assumed to be two-dimensional with two initially-isolated reservoir zones, intersected by an arbitrary number of wells, part of which are active producers while others can be penetrating wells with commingled completion, in addition to other communicating media. The well test duration is assumed long enough for the pressure-transient data to be affected by fluid communication. To demonstrate the applicability of the new model, a synthetic case study is presented to diagnose a fluid-communication mechanism. The system under consideration consists of two isolated reservoirs and two wells: a single producer completed in the top reservoir in which pressure responses are measured, and an offset well connecting both reservoirs through a fluid communication mechanism. Using the model, type-curves have been utilized to diagnose the hydraulic communication in the offset well. The connectivity of the communication channel in the offset well is also estimated by matching the pressure-transient responses of the model with the measured data. The rate of crossflow between the two reservoirs is also quantified as a function of time. It is observed from the log-log plot that higher connectivity values of the cement sheath causes a steeper merging ramp in the transition region, following a period dominated by the producing reservoir. Although the rate of crossflow depends on the magnitude of the connectivity, it is observed that there is an upper limit controlled by the rock and fluid properties of the individual reservoirs. In addition, the pressure regime at the location of the offset well plays an important role in the rate of crossflow. This study presents a novel analytical approach to detect communication from pressure-transient data, and to quantify the magnitude of crossflow rates between reservoir zones. The formulation captures the influence of interference between wells caused by production. While complementing diagnostic information from other sources to confirm fluid movement from isolated zones, the method also quantifies the connectivity of the communicating media, and the amount of crossflow rates as a continuous function of time.

Injection period pressure transient behaviour of two-phase water-oil flow: A semi-analytical study

2020 ◽  
Vol 14 (2) ◽  
pp. 6719-6733
Author(s):  
Althaf Shafeer ◽  
Lee Jang Hyun ◽  
Tarek Arbi Ganat ◽  
Azeb Demisi Habte
Keyword(s):  
Skin Effect ◽  
Mobility Ratio ◽  
Two Phase ◽  
Positive Skin ◽  
Pressure Transient ◽  
Injection Period ◽  
Transient Behaviour ◽  
Wellbore Storage ◽  
Phase Water ◽  
The Impact

This paper presents a study on the pressure transient behaviour during the injection period in a vertical well in the presence of wellbore storage and skin effect. The two-phase water-oil radial flow problem is solved using a semi-analytical technique called the Laplace-Transform Finite-Difference method. Moreover, the factors that influence the degree of wellbore storage and skin effect are analysed. The results demonstrated that the effect of wellbore storage on the pressure transient behaviour is significant during the early times. Factors such as compressibility of fluid, effective wellbore volume and endpoint mobility ratio significantly affect the duration of wellbore storage. The impact of the skin during the injection period is significant on the pressure transient behaviour and could last for a longer duration. A substantial effect of skin is observed for a positive skin factor and unfavourable endpoint mobility ratio. In addition, the duration of the effect is directly proportional to the thickness of the skin zone. Hence attention must be given to the parameters that could prolong these effects and included in the solution methods to precisely interpret the injection period pressure transient behaviour for a better estimation of the reservoir and well properties.   

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