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Abstract A tight gas reservoir is commonly defined as a reservoir having less than 0.1 millidarcies permeability. There are several basic concepts and field cases of different well tests in tight gas reservoirs in the literature, but not presented as a general guide. In this paper, we gather valuable information and provide a useful guide to the most important well tests in tight gas reservoirs. Generally due to low permeability of these reservoirs, a well will not flow initially at measurable rates and conventional well testing cannot be applied. Therefore, fracture stimulation must be considered. Many authors present procedures for design of pre and post-frac tests. The pre-frac test permits calculating preliminary estimates of reservoir permeability and initial pressure. Because of economic and environmental reasons, short duration procedures are of interest. Hence, prime candidates are pre-frac, short time, small volume, closed chamber tests. These tests have to be analyzed by special methods to provide improved values of reservoir parameters. In this study, we also present a review of some aspects in tight gas well testing like pressure-dependent permeability, estimation of pseudo-time at the average pressure of the region of influence, supercharge effect, the problem of treating the pressure-dependent product ยตct during pre-frac test analysis and the concept of instantaneous source response Introduction Large decreases in production and increases in demand for fossil-fuels cause the economic gas production from unconventional resources (tight gas, coal bed methane (CBM), and gas hydrate) to be a great challenge. Huge reserves, longterm potential, low gas prices and some other factors account for the great influence of these resources on the future of energy. There is no formal definition for "Tight gas". Commonly used definition, describes tight gas reservoirs as those having permeabilities less than 0.1 millidarcies. Recently, the German Society for Petroleum and Coal Science and Technology (DGMK) defined tight gas reservoirs as those with average effective gas permeability of less than 0.6 mD. "Ultra tight" gas reservoirs may exhibit permeabilities down to 0.001 mD. To improve the recovery of this resource, GFREE research program has been created at the University of Calgary. GFREE stands for:Geoscience aspects (G) Formation evaluation by petrophysics and well test (F) Reservoir drilling, completion and stimulation (R) Reservoir Engineering (RE) Economics and long run supply curves (E) As a part of the activities of this research program, we have concentrated on Formation evaluation (F) by well testing, and conducted a literature survey which is presented in this paper. Well testing is generally done to estimate hydrocarbon (here gas) in-place and recoverable resources. Initial pressure is a critical parameter not only for estimating gas in-place, but also for determining how much field development is required and whether or not the field is overdeveloped. In addition to pi, well testing provides an estimate of permeability. A problem associated with well testing in tight gas sands is that usually long times are required to reach redial flow, due to their extremely low permeabilities.
- North America > United States > Texas (0.68)
- North America > Canada > Alberta > Census Division No. 6 > Calgary Metropolitan Region > Calgary (0.25)
- Overview (1.00)
- Summary/Review (0.88)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Tight gas (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
Abstract This paper presents a simplified method for drawdown and buildup analysis of naturally fractured reservoirs. This method permits handling of wellbore storage and matrix blocks of different shapes. Although there are excellent techniques in the literature for handling these problems, all of them require the use of specialized software. The technique developed in this paper allows approximate, yet sound solutions to these problems, using a few columns in a spread sheet. The method allows calculation of parameters such as fracture permeability, wellbore storage, skin, storativity ratio ?, interporosity flow coefficient ฮป, fracture spacing, number of fractures intercepted by the wellbore and amount of secondary mineralization within fractures. The method is illustrated with actual data from fractured reservoirs. Introduction There are excellent commercial software packages in the oil industry for evaluating well testing data from dual porosity models. The idea behind the methods presented in this paper is not to replace sophisticated software packages but to provide step by step simplified methods that still give reasonable results. Some of the basic principles behind well test analysis of naturally fractured reservoirs have been published by Barenblatt and Zheltov, Warren and RootKazemi, de Swann, Najurieta, and Streltsova. Aguilera published functions for handling various matrix block shapes. Several type curves have appeared in the literature (literally hundreds of type curves) including works by Bourdet and Gringartenand Jalali and Ershagui. Still the problem of non-uniqueness will be with us anytime that we analyze transient pressure data, due to the inverse nature of the problem we are dealing with. Drawdown Test Flow pressure (pwf) as a function of time (t), capable of matching recorded pressures that include skin and wellbore storage in a dual porosity system, can be calculated from the equation: Equation (1) (Available in full paper) where (ฮทgc) is a general hydraulic diffusivity that includes wellbore storage; c1, c2 and c3 are constants that apply to either customary or SI units. Other nomenclature are defined at the end of the paper. The general hydraulic diffusivity can operate under conditions of restricted or unrestricted interporosity flow. Restricted Interporosity Flow This section presents the equations for generating a synthetic drawdown. The procedure starts with an estimate of the ratio ฮฑ' between the shape factor of matrix blocks and the shape factor of a stratum model. This is given by: Equation (2) (Available in full paper) A function, f (t, ฮป) for the case of restricted interporosity flow is determined from: Equation (3) (Available in full paper) Next a hydraulic diffusivity (ฮทg) for the dual porosity system, without wellbore storage, is calculated from: Equation (4) (Available in full paper) A pressure change (ฮp)c that includes wellbore storage, C, is given by: Equation (5) (Available in full paper) A function of Equation that includes wellbore storage is determined from: Equation (6) (Available in full paper) The storativity ratio (ฯ) is calculated from: Equation (7) (Available in full paper) Eqs. 2 to 7 permit calculating the general hydraulic diffusivity (ฮทgc) from: Equation (8) (Available in full paper)
Abstract Permeabilities from layer to layer can vary significantly in naturally fractured reservoirs. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally fractured reservoir. The research was conducted with a model that contains ten layers that are naturally fractured. The ten-layer model is validated by comparing its drawdown and buildup behavior against the behavior of a single-layer model. It is shown that permeability of the 10-layered reservoir calculated using a single-layer method will be much larger than the geometric mean and even the arithmetic mean, and will reflect the two layers with the largest permeabilities. If this is used in reservoir studies together with the total net pay, it can lead to very optimistic forecasts. The problem of multi-layered permeability behavior may be recognized by a pressure derivative indicating partial completion effects even if the well is perforated in all fractured layers. During a buildup this recognition is more difficult because the shape of the buildup curve is affected by the length of the flow period previous to shut-in and the length of the wellbore storage period. Conclusions apply strictly only to the data set presented in this study. These conclusions, however, compare favorably with my observations in other naturally fractured reservoirs. Introduction Outcrop information, imaging logs, and production logs have shown that in some cases naturally fractured reservoirs are composed by many layers. The thinner the layer the smaller the fracture spacing (or distance between natural fractures). Under these circumstances some of the fractures might be intersected by the wellbore and some might not as shown on Figure 1. A production log would show only the fluid entrance points into the wellbore. It is important to emphasize that the production log would not give an indication of net pay in the naturally fractured reservoir, only an indication of where the wellbore intersects the most important fractures. It is not unusual to see from a production log that out of 100 ft. perforated in a fractured reservoir only 5 to 10 ft. contribute production into the wellbore even if the 100 ft. are true net pay. This is the result of a typical situation in most naturally fractured reservoirs I am familiar with, i.e., that the matrix has a very low permeability which does not permit efficient fluid flow into the wellbore. The same tight matrix, however, can flow very efficiently into the natural fractures. FIGURE 1: Schematic of naturally fractured layered reservoir. Production log shows a couple of zones where fluids enter the wellbore. However, the whole section from top to bottom is net pay. (Available in full paper) One of the first papers dealing with pressure behavior of layered reservoirs was published by Leftkovits et al. There was no communication between layers except at the wellbore. Later Russell and Prats studied the practical aspects of interlayer crossflow, and concluded that the early time response would be similar to the response of a well draining a layered reservoir with no cross flow.
Abstract Permeabilities from layer to layer can vary significantly in naturally fractured reservoirs. This study makes a comparison of geometric mean fracture permeability with permeabilities from well testing data in a layered naturally fractured reservoir. The research was conducted with a model that contains 10 layers that are naturally fractured. The 10-layer model is validated by comparing its drawdown and buildup behavior against the behavior of a single-layer model. It is shown that permeability of the 10-layered reservoir calculated using a single-layer method will be much larger than the geometric mean and even the arithmetic mean, and will reflect the 2 layers with the largest permeabilities. If this is used in reservoir studies, it can lead to very optimistic forecasts. The problem of multi-layered permeability behavior may be recognized during a drawdown by a pressure derivative indicating partial completion effects even if the well is perforated in all fractured layers. During a buildup this recognition is more difficult because the shape of the buildup curve is affected by the length of the flow period previous to shutin. Introduction Outcrop information, imaging logs and production logs, have shown that in some cases naturally fractured reservoirs are composed by many layers. The thinner the layer the smaller the fracture spacing (or distance between natural fractures). Under these circumstances some of the fractures might be intersected by the wellbore and some might not as shown on Figure 1. A production log would show only the fluid entrance points into the wellbore. It is important to emphasize that the production log would not give an indication of net pay in the naturally fractured reservoir, only an indication of where the wellbore intersects the most important fractures. It is not unusual to see from a production log that out of 100 ft perforated in a fractured reservoir only 5 to 10 ft contribute production into the wellbore even if the 100 ft are true net pay. This is the result of a typical situation in most naturally fractured reservoirs I am familiar with, i.e., that the matrix has a very low permeability which does not permit efficient fluid flow into the wellbore. The same tight matrix, however, can flow very efficiently into the natural fractures. One of the first papers dealing with pressure behavior of layered reservoirs was published by Leftkovits et al. There was no communication between layers except at the wellbore. Later Russell and Prats studied the practical aspects of interlayer cross flow, and concluded that the early time response would be similar to the response of a well draining a layered reservoir with no cross flow. Prijambodo et al studied the early time performance of a well in a reservoir with cross flow and concluded that the pressure behavior was remarkably different from that of an equivalent single layer system. They indicated that the early time response could be divided in flow periods.
Abstract Analytical solutions are presented for the analysis of dual-porosity systems intercepted by hydraulic vertical fractures of finite conductivity. The well can be in an infinite or a bounded dual-porosity system. The outer boundary can be sealed or it can be at constant pressures. pressures. The following flow periods have been identified:A bilinear flow period typical of finite conductivity fractures. This is recognized by a quarter slope in a conventional log-log crossplot of pressure differential vs. time. A transition period due to flow from the matrix into the natural fractures. A pseudo radial flow period recognized by a straight line in a conventional semilograthmic plot. Boundary effects which can be due to a sealed boundary or an outer boundary at constant pressure. Recognition of these flow periods allow calculation of parameters such as omega, lambda, distance between natural fractures, permeability, fracture conductivity and permeability, fracture conductivity and half-fracture length. This is illustrated with an example. Introduction Naturally fractured reservoirs have been the object of intensive studies during the last few years. The effect of a fully penetrating vertical fracture of infinite conductivity in a homogeneous reservoir has been studied by Prats, Prats et al., Russel and Truitt, Prats, Prats et al., Russel and Truitt, van Everdingen and Meyer, and Gringarten et al. Many times naturally fractured reservoirs are hydraulically fractured. For example, this has happened repeatedly in the Austin Chalk and the Appalachian Basin. Houze et al. studied this problem by considering an infinite problem by considering an infinite conductivity vertical fracture in an infinite acting reservoir and concluded that a log-log plot of vs. time should result in an early straight line with a 0.5 slope, followed by a transition period, and reaching pseudo radial flow when pressure in matrix and fractures reach an equilibrium. Lancaster and Gatens have presented some practical guidelines regarding analysis methods for hydraulically fractured wells in dual-porosity reservoirs. They conclude that pre-fracture well test data are important for a proper post-fracture well test interpretation. post-fracture well test interpretation. From the pre-fracture test one can obtain natural fracture permeability, lambda and omega, critical parameters for the postfracture well test interpretation. postfracture well test interpretation. Aguilera has presented an approximate solution of linear flow in naturally fractured reservoirs. P. 193
- Geology > Geological Subdiscipline > Geomechanics (0.34)
- Geology > Structural Geology > Tectonics > Compressional Tectonics > Fold and Thrust Belt (0.34)
- North America > United States > West Virginia > Appalachian Basin (0.89)
- North America > United States > Virginia > Appalachian Basin (0.89)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Austin Chalk Formation (0.89)
- (16 more...)
Abstract Bottom hole buildup pressures on three Wyoming pumping wells have been determined based on liquid level in the annulus as determined from a computerized acoustic device. These buildup data correspond to a naturally fractured reservoir which produces oil, gas and water. Basic formulations and three case histories are presented:The case of a well with after flow effects where the buildup data are properly matched using type curves for dual-porosity systems with restricted (pseudo steady state) interporosity flow and the pressure derivative. The case of a stimulated well in a naturally fractured reservoir. In this situation a conventional log-log crossplot of delta p vs. time results in two parallel straight lines with slopes equal to 0.5. Separation between the two lines allows calculation of the storativity ratio, omega. The case of a well in a layered naturally fractured reservoir with variable afterflow effects. In this case a log-log plot of delta p vs. time shows two parallel straight lines with slopes equal to 1.0. A good match of the data is obtained with a dual-porosity model and the pressure derivative starting at the second 1.0 slope straight line. Acquisition of the raw data, conversion into bottom hole buildup pressures, and analysis utilizing dual-porosity models are presented in detail. It is concluded that pumping wells in naturally fractured reservoirs can be properly evaluated when all phases flowing are taken into account. The same procedure and formulations presented in this work can be utilized for analysis of conventional single-porosity reservoirs by making Warren and Root's omega equal to 1.0. DESCRIPTION OF EQUIPMENT The Automatic Acoustic Bottomhole Pressure system determines the depth to the liquid level, and measures and records the casinghead pressure in a well, unattended. The frequency of data point collection may be specified by the operator. The equipment consists of an electronic package, a wellhead assembly, interconnecting cables, a 12 volt battery, and a small gas supply container. P. 577^