Modeling the Interfering Effects of Gas Condensate and Geological Heterogeneities on Transient Pressure Response

SPE Journal ◽  
2013 ◽  
Vol 18 (04) ◽  
pp. 656-669 ◽  
Author(s):  
H.. Hamdi ◽  
M.. Jamiolahmady ◽  
P.W.M.. W.M. Corbett
Keyword(s):  
Present Report ◽  
Early Time ◽  
Pressure Response ◽  
Gas Condensate ◽  
Well Test ◽  
Transient Pressure ◽  
Sensitivity Coefficients ◽  
Vertical Permeability ◽  
Single Well ◽  
The Impact

Summary Numerous publications have investigated the effect of gas condensate fluid on the transient pressure well-test (WT) response. However, to the best of our knowledge, its combined effect with geology has rarely been studied. Our findings in the present report demonstrate that geology can complicate the WT response and make it difficult for interpretation. In this study, the impact of geological heterogeneities on the WT response of a commingled braided fluvial gas condensate reservoir has been investigated. Numerical WT data were generated for a single-well model with a commercial compositional reservoir simulator. Several sensitivity simulations were performed to explore the effects of correlation length, vertical permeability, production rate, and drawdown time on the pseudopressure-derivative curves. The WT weighting kernel function and the calculated well-pressure sensitivity coefficients were implemented to demonstrate different trends of drawdown and buildup responses encountered in this study. The results clarified the idea that some geological heterogeneities and production parameters can alter pressure distribution and condensate saturation and mask the native model WT signatures. In this exercise, it was demonstrated that ramp effect, a geologically complex phenomenon in high-net/gross commingled reservoirs, is affected by the condensate formation. This interfering phenomenon is reflected on the derivative curves and is magnified in the presence of the shorter correlation lengths, the lower vertical communications, and the higher production rates. We also examined the stepwise stripping of the reservoir heterogeneity, demonstrating the significant impact of some facies on the buildup and drawdown transient pressure response. The time-dependent sensitivity coefficients were calculated to show that the drawdown test is sensitive to effective permeability in near-wellbore regions, in which condensate is prone to build up with time. In the buildup, on the other hand, the condensate saturation is almost invariant with time and affects the early-time region. This work leads toward better understanding of the influence of geology in gas condensate WT interpretation of fluvial reservoirs.

Methods To Obtain Quick Estimates of Formation Parameters in Interference Tests Derived From Features of the Line-Source Solution—Theory and Application

2013 ◽  
Vol 16 (01) ◽  
pp. 29-39
Author(s):  
Pierre-David Maizeret
Keyword(s):  
Line Source ◽  
Time Lag ◽  
Early Time ◽  
Integral Function ◽  
Pressure Response ◽  
Well Test ◽  
Diagnostic Plot ◽  
Single Well ◽  
Interference Test ◽  
Interference Tests

Summary Interference testing is the oldest, but still the most effective, way of establishing communication between wells and determining the interwell-reservoir transmissibility. Yet these tests are not run frequently because often the results are difficult to analyze as a result of unforeseen complications. This paper presents practical methods derived from the properties of the line-source solution that is used to design and interpret effective interference tests. In single-well transient tests, early-time features of the exponential integral function occur too early to be observed. However, these features appear much later in an interference test and can be used in an observation well to estimate the storativity and transmissibility ratios of the reservoir. The pressure response and the log derivative of the pressure intersect on the log-log diagnostic plot, and the pressure response itself exhibits an inflection point. With these characteristics, simple geometrical methods are proposed to estimate reservoir parameters. Moreover, a new expression of the “lag time,” or delay in the response, is formulated. The particular case of falloff or buildup is studied in detail, because the time lag in the reservoir response can bring extra information. A field example is included to demonstrate the application of these methods to actual data and their usefulness to a practicing well-test engineer.

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.

Pulse Tests and Other Early Transient Pressure Analyses for In-Situ Estimation of Vertical Permeability

1974 ◽  
Vol 14 (01) ◽  
pp. 75-90 ◽  
Author(s):  
George J. Hirasaki
Keyword(s):  
Pressure Response ◽  
Gravity Drainage ◽  
Transient Pressure ◽  
Type Curve ◽  
Pulse Test ◽  
Recovery Processes ◽  
Vertical Permeability ◽  
Constant Rate ◽  
Rate Test

Abstract Formation vertical permeability is often the dominant influence in water or gas coning into a well, in gravity drainage of high-relief reservoirs, and in interlayer crossflow in secondary recovery projects. The advantages of either conducting a projects. The advantages of either conducting a pulse test or analyzing the early transient pressure pulse test or analyzing the early transient pressure response of a constant-rate test compared with previous techniques are simplicity of interpretation, previous techniques are simplicity of interpretation, short duration of test, and minimum interference from conditions some distance from the test well. The pulse test has a further advantage over the constant-rate test in that the rate does not have to be kept constant during the short flow period.Presented are the development of the theory and the curves of the dimensionless response time used in interpreting field data obtained by these techniques. The vertical permeability is determined with the pulse test from the time to the maximum pressure response and with the constant-rate test pressure response and with the constant-rate test from the extrapolated time to zero pressure response from the inflection point.Applications of the techniques to layered systems and to an oil zone with underlying water are demonstrated with results of numerical simulations. The vertical-permeability pulse test has been used to estimate the vertical permeability of a low-permeability zone in the Fahud field, Oman. Introduction The formation vertical permeability is often a dominant influence in reservoir recovery processes with vertical fluid flow such as water or gas coning, gravity drainage of high-relief reservoirs, the rising steam process, and displacement by water or gas in a heterogeneous formation. How reliably numerical reservoir simulators can predict the recovery performance of these processes depends upon how performance of these processes depends upon how accurately the significant reservoir parameters are estimated. Furthermore, in simulating a reservoir in two dimensions, the validity of the assumption of vertical equilibrium is based on the value of the vertical permeability.With the previously mentioned recovery processes, the reservoir cannot be modeled as a homogeneous reservoir with a single fluid. A well that has fluid coning or that is producing by gravity drainage will often have a fluid contact intersecting the well and thus dividing the reservoir into zones of differing mobility and compressibility. Reservoir stratification on a microscopic scale will result in a vertical permeability that is less than the horizontal permeability that is less than the horizontal permeability; but stratification on a macroscopic permeability; but stratification on a macroscopic scale will divide the reservoir into zones of differing permeabilities. Thus the design and interpretation permeabilities. Thus the design and interpretation of a vertical-permeability test for most practical reservoir situations will require that the reservoir zonation be represented.Transient pressure techniques for estimating in-situ vertical permeability have been introduced by Burns and by Prats. Both techniques require injection or production at a constant rate from a short perforated interval and measurement of the pressure response at another perforated interval pressure response at another perforated interval that is isolated from the first by a packer. The interpretation technique of Burns required a computer-generated type curve or a single-phase numerical reservoir simulator. This type-curve approach is applicable for an anisotropic, homogeneous, infinite reservoir model, and the numerical simulator with a regression analysis program is needed for finite or layered reservoir models. The technique presented by Prats did not require a computer program because the result of the analysis was presented on a single graph. The horizontal and vertical permeabilities could be estimated from the slope and the intercept of the pressure response and, the appropriate value from the graph. The method of Prats was based on an infinite, anisotropic, Prats was based on an infinite, anisotropic, homogeneous reservoir model.The pulse test and early transient analysis techniques presented here were developed to provide a simple means of interpretation for layered provide a simple means of interpretation for layered systems. Some advantages are thatno computer program is requiredlayered reservoirs can be program is requiredlayered reservoirs can be represented;test duration is shorter than for previous methods; andthere is less interference previous methods; andthere is less interference from reservoir conditions some distance from the test well. SPEJ P. 75

Pulse-Test Response of a Two-Zone Reservoir

1970 ◽  
Vol 10 (03) ◽  
pp. 245-256 ◽  
Author(s):  
E.G. Woods
Keyword(s):  
Flow Rate ◽  
Single Layer ◽  
Pressure Response ◽  
Test Results ◽  
Well Test ◽  
Reservoir Model ◽  
Reservoir Properties ◽  
Pulse Test ◽  
Pulse Testing ◽  
Single Well

Woods, E.G., Member AIME, Esso Production Research Co., Houston, Tex. Abstract A mathematical investigation of pressure response of two-zone reservoirs indicates apparent transmissibility (kh/ ) obtained by pulse testing is always equal to or greater than the total transmissibility of the zones, and that apparent storage (phi ch) is always equal to or less than the total storage of the zones. These apparent zone properties approach total properties as vertical fluid communication between zones increases. The presence of non uniform wellbore damage in the zones alters the division of flow between zones, and consequently, alters their apparent transmissibility ratio. In the absence of wellbore damage. the flow-rate ratio is a good estimator of the transmissibility ratio of the zones. A procedure is proposed for advantageously using differences in reservoir properties determined by single-well tests and pulse tests to describe flow properties of two-zone reservoirs. A numerical properties of two-zone reservoirs. A numerical example is included. Introduction Pulse tests, interference tests, and single-well pressure buildup or drawdown tests have been used pressure buildup or drawdown tests have been used to estimate reservoir properties. These pressure transient tests are normally analyzed with mathematical models which assume that the reservoir is a homogeneous single layer. Various techniques for analyzing single-well test data to obtain information about the properties of layered reservoirs have been shown by others to have limited applicability. This mathematical study was undertaken to determine what errors could be caused by interpreting pulse tests (in a multizone reservoir) with a single-layer model. Pulse testing is based on the measurement and interpretation of a pressure response in one well to a transient pressure disturbance introduced by varying flow rate at an adjacent well. The measured pressure response is usually a few hundredths of a pressure response is usually a few hundredths of a pound per square inch. Pulse-test terminology is pound per square inch. Pulse-test terminology is shown in Fig. 1; Johnson et al. give a complete description of pulse testing. Measured at the wellhead or in the wellbore, pressure response is a function of reservoir pressure response is a function of reservoir transmissibility (T=kh/mu) and diffusivity (n = k/phi cmu) in the region between the two wells; from these two quantities reservoir storage ( = /n=phi ch) can be derived. The analysis presented here discusses additional reservoir information made available by pulse testing and shows that single-well test and pulse-test results can be combined to give more information about a two-zone reservoir than either type of test alone. Also, procedures are given for estimating the magnitude of error if test results of a two-one reservoir are interpreted with the assumption that it is a one-zone, vertically homogeneous, reservoir. Discussions of theoretical work, field data requirements, interpretation procedure, and a numerical example follow. Details of the mathematical model are given in the Appendix. THEORETICAL STUDY - TWO-ZONE MODEL Reservoir Model - Assumptions and Boundary Conditions A reservoir model consisting of two zones penetrated by two wells, each of which is completed in both zones was assumed (Fig. 2). SPEJ p. 245

scholarly journals Development of a Semi-Analytical Type Curve of Transient Pressure Response in Complex Well-Reservoir Architectures

2019 ◽  
Vol 20 (2) ◽  
pp. 61-69
Author(s):  
Ibrahim Saeb Salih ◽  
Hussain Ali Baker
Keyword(s):  
Transient Response ◽  
Pressure Response ◽  
Skin Permeability ◽  
Well Testing ◽  
Well Test ◽  
Transient Pressure ◽  
Well Test Analysis ◽  
Pressure Transient ◽  
Analytical Approaches ◽  
Complex Well

The objective of the conventional well testing technique is to evaluate well- reservoir interaction through determining the flow capacity and well potential on a short-term basis by relying on the transient pressure response methodology. The well testing analysis is a major input to the reservoir simulation model to validate the near wellbore characteristics and update the variables that are normally function of time such as skin, permeability and productivity multipliers. Well test analysis models are normally built on analytical approaches with fundamental physical of homogenous media with line source solution. Many developments in the last decade were made to increase the resolution of transient response derivation to meet the complexity of well and flow media.    Semi-analytical modeling for the pressure transient response in complex well architecture and complex reservoirs were adopted in this research. The semi analytical solution was based on coupling the boundary condition of source function to the well segment. Coupling well-reservoir on sliced based technique was used to re-produce homogenous isotropic media from several source functions of different properties. The approach can model different well geometries penetrated complex reservoirs. A computer package was prepared to model the pressure transient response of horizontal, dual-lateral, multi-lateral wells in complex anisotropic reservoirs, multilayered, compartmentalized, system of various boundary conditions such as: bottom support aquifers, edge supported, gas caps, interference of injection. The validity of the proposed model was successfully checked by using the commercial simulator.

Interpretation of formation permeability and pressure responses from wireline formation testing with consideration of interlayers

2018 ◽  
Vol 6 (4) ◽  
pp. T835-T847 ◽  
Author(s):  
Min Yang ◽  
Daoyong Yang ◽  
Andrew Chen
Keyword(s):  
History Matching ◽  
Field Data ◽  
Early Time ◽  
Flow Regimes ◽  
Fluid Viscosity ◽  
Time Behavior ◽  
Transient Pressure ◽  
Hydrocarbon Reservoir ◽  
Vertical Permeability ◽  
The Difference

We have developed a workflow to interpret formation permeability in a hydrocarbon reservoir with consideration of interlayers by numerically simulating the measured pump-out flow and pressure responses from wireline formation testing (WFT). With the field data obtained from a dual packer tool in the deepwater Gulf of Mexico, we have developed and validated a high-resolution numerical model to simulate the fluid-sampling process together with transient pressure. History matching has been performed with field data to assess the effective thickness and then interpret the permeability for each flow unit. In addition to generating eight cases under various configurations of laminated layers, we use pressure buildup derivatives obtained from packers and observation probes as a diagnosis tool to examine the effect of the interlayer on WFT measurements. Oil-based mud-filtrate invasion affects the early-time behavior of pressure transients because of the associated changes in fluid viscosity and compositions. Low vertical permeability can behave as a vertical barrier for the flow in a WFT tool, indicating the difference contrast in permeability between individual flow units. As for the field case, effective water horizontal permeabilities for tests 1 and 2 are 14.0 and 10.6 mD, respectively. Low vertical permeability results in a distortion in the derivatives, particularly during the transition between flow regimes. In a laminated reservoir, a radial flow regime will develop when the radial length of interlayer is greater than the vertical formation interval and when the complete circular shape of interlayer is formed. It is recommended that any observation probe be positioned in or below the interlayer to accurately define the vertical communication of interlayers and its configuration. If dual packers and observation probes are located in the same zone, their pressure responses exhibit the same flow regimes; otherwise, different pressure responses can be developed in the observation probes when a partially sealing interlayer exists.

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