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Momeni A.,Amirkabir University of Technology | Dadvar M.,Amirkabir University of Technology | Hekmatzadeh M.,IOR Research Institute | Dabir B.,Amirkabir University of Technology
International Journal of Multiphase Flow | Year: 2017

Condensate dropout in near a wellbore region in gas condensate reservoir is the main reason of low well deliverability. Many researchers have studied gas and condensate relative permeabilities (RPs) in this region to find the condition for better deliverability. It is known that RP is a function of capillary number in low interfacial tension (IFT) systems such as gas-condensate. The positive dependency of RPs to velocity which is referred to as “positive coupling effect” is related to the simultaneous flow of gas and condensate associated with intermittent opening and closure of channels in porous media. The negative dependency of RPs to velocity named “negative inertia” is due to non-Darcy high-velocity flow. In this study, a 3D pore network modeling is developed to investigate fluids distribution in a gas-condense system at a pore scale to find out the effects of IFT and velocity on RPs. A new method is developed that applies a flash calculation in all throats in the network to estimate the amount of accumulated condensate in throats' corners at different time steps. A modified form of Poiseuille's law for polygonal cross-sectional throats is used to find and update pressure field and fluids distribution in the network and to determine the quantity of pushed out condensate from closed throats to neighboring throats. The displacement mechanism is considered to be determined by the volume of displaced phases in throats without applying any correlation. Simulation results indicate that gas and condensate RPs are increased by an increase in velocity. However, RPs sensitivity to velocity is reduced by increasing IFT which is in agreement with previous studies. © 2017 Elsevier Ltd

Sureshjani M.H.,IOR Research Institute | Gerami S.,IOR Research Institute
Journal of Canadian Petroleum Technology | Year: 2011

Modern production-decline analysis is a robust technique for analysis of production data from a well under variable operating conditions. It uses production rates and flowing pressures to provide reliable estimates of recoverable reserves and fluid in place. The mathematics behind this technique is similar to that of pressuretransient theory; however, the focus is different. It deals with longterm variable production data instead of short-term constant-rate transient data. Using modern decline analysis for two-phase-flow conditions (e.g., gas/condensate reservoirs) is under question because of the single-phase-flow assumption in the development of the "material-balance time" function. This is a time function that converts any decline (e.g., exponential decline) to harmonic decline to account for variable operating conditions. The purpose of this work is to develop a model to use the concepts of modern techniques for analyzing production data of single-porosity gas/condensate reservoirs. For this purpose, the governing flow equation is linearized, using appropriately defined pseudopressure and pseudotime functions. Then, the solution is obtained for constant-well-rate condition. This is followed by employing the superposition theorem to account for variable well pressure/rate conditions, resulting in definition of two-phase material-balance pseudotime. The solution developed here is coupled with an appropriate material-balance equation and used to estimate the average reservoir pressure and original gas in place from analyzing production data. The dependency of relative permeability on capillary number and non-Darcy flow is included in the formulation. Verification of the proposed method is obtained with the analysis of synthetic production data using a series of fine-grid compositional numerical simulations over a typical range of gas/condensate-reservoir parameters.

Sureshjani M.H.,IOR Research Institute | Gerami S.,IOR Research Institute
Journal of Petroleum Science and Engineering | Year: 2011

Analysis of production data is an important method for estimating recoverable reserves and probable life of the reservoirs. Robust techniques for analysis of production data have been developed and widely used for many years. These methods range from the traditional Arps decline method to modern production data analysis. The most recent techniques are based on material balance time to account for variable operating conditions. In these methods, production rate and flowing bottom hole pressure must be known. A major limitation of many existing modern techniques is volumetric assumption of the reservoir.This paper presents a new model that accounts for non-volumetric effects of edge aquifers on production data analysis of single phase oil reservoirs by defining a new material balance time function. This new time function and material balance time help us to introduce flowing material balance (FMB) equations for such reservoirs. Validity of these equations is justified using analytical solutions. For development of analytical solutions, special simplifying assumptions are considered. To justify these assumptions, comparison is made using a commercial numerical reservoir simulator across some ranges of reservoir parameters.Furthermore, based on the validated FMB equations and obtained analytical flow equations, specific procedures are developed for parameter estimation of such reservoirs. The use of these procedures in estimation of oil in place and reservoir external radius is demonstrated using synthetic examples. On the basis of the considered assumptions, the proposed procedures cannot be applied to multi-phase flow conditions, reservoirs with other types of aquifer (such as bottom aquifer), and gas reservoirs.We also show that the given FMB equations are applicable for any irregularly shaped reservoir which is partially contacted with a non-cylindrical limited edge aquifer. For such reservoir geometries, numerical solution is used for justification. This is followed by introducing a simple equation for predicting average reservoir pressure. © 2011 Elsevier B.V.

Mollaei A.,IOR Research Institute | Maini B.,University of Calgary
Journal of Canadian Petroleum Technology | Year: 2010

A review of important issues in steam injection in naturally fractured reservoirs (NFRs) is presented. The effect of temperature on physical properties of crude oils and rocks and the thermochemical alteration of crude oil are discussed. The recovery of oil from NFRs can be modelled as a two step process: first the oil is expelled from the matrix blocks through mechanisms that impose a pressure gradient within each matrix block and then it is swept through the fracture network to a production well by mechanisms that impose a pressure gradient within the fracture network. The recovery mechanisms associated with steam injection in NFRs and their characteristic times are presented. The most important recovery mechanism in matrix blocks is differential thermal expansion between oil and the matrix pore volume and the strongest mechanism in fracture network is the reduction of viscosity ratio (μ 0/μ w). The matrix oil recovery mechanisms are relatively independent of oil gravity, making steam an equally attractive recovery process in fractured light and heavy oil reservoirs. The mechanism and impact of CO 2 generation during steam injection in carbonate reservoirs are discussed. The rate of CO 2 generation is controlled by the rate of heat conduction from fracture into the matrix. For a specific reservoir the rate of heat conduction is a function of temperature and injection rate of steam and these can be optimized to make use of the in situ generated CO 2.

Heidari Sureshjani M.,IOR Research Institute | Clarkson C.R.,University of Calgary
Journal of Petroleum Science and Engineering | Year: 2015

Transient linear flow is the dominant flow regime in many multi-fractured horizontal wells completed in very low permeability reservoirs. Therefore, development of reliable methods for analyzing production data from this flow regime is of great value. The common methodology for production analysis of this flow period is use of square-root-time plot in which normalized pressure (or pseudopressure for gas) is plotted vs. square-root-time. This method has been proved to be acceptable for systems with infinite conductivity hydraulic fractures. The square-root-time plots for such systems exhibit a zero intercept. When analyzing production histories of real examples, we observe cases for which the square-root-time plot exhibits a straight-line trend with a positive intercept. We demonstrate that this behavior can be attributed to systems with finite conductivity hydraulic fractures. For constant-pressure systems with finite conductivity hydraulic fractures, the square-root-time plot methodology overestimates fracture half-length. This has been shown using synthetic examples. To solve this problem, we have developed a new inverse solution methodology which is based on an analytical formulation. We have defined new plotting functions and illustrated that a plot of these functions against each other in the formation linear flow period exhibits a linear trend. From the slope of this plot, the true value of fracture half-length can be estimated. Also, fracture conductivity can be determined from the intercept. The proposed methodology has been verified using synthetic tight oil examples. We have also applied it for several tight gas examples. We have analyzed production data for two field examples using the conventional square-root-time plot methodology and the new inverse solution methodology. Our analysis reveals that the square-root-time plot methodology considerably overestimates the fracture half-length for these examples. © 2015 Elsevier B.V.

Jazayeri Noushabadi M.R.,Montpellier University | Jazayeri Noushabadi M.R.,IOR Research Institute | Jourde H.,Montpellier University | Massonnat G.,Total S.A.
Journal of Hydrology | Year: 2011

Determination of permeability in fractured and karstic carbonate reservoirs is of great importance as reservoirs of this type represent a significant proportion of the aquifers and petroleum reservoirs in the world. In fact at a given scale the permeability values determined from the hydrodynamic response to a well test can vary dramatically from one observation well to another. In this study we investigate such permeability variations and their origins at both local and regional scales.Permeability values for a fractured and karstic carbonate aquifer (Lez spring hydrogeological catchment, Southern France) have therefore been analyzed from well tests conducted at local and regional scales: (i) interference tests at the field site scale, (ii) pulse tests at the reservoir scale.Analyzing and comparing the hydrodynamic responses to the pumping tests at both scales show that (i) mean estimated permeability values can increase with observation scale in this particular carbonate reservoir, (ii) at a given scale these values depend dramatically on the location of the observation well used for permeability estimations as the connectivity between the well and the high permeability flow path network depends on this location, and (iii) the water table level or the drilling depth of the observation well appear to be key parameters when estimating permeability values as they also control the connectivity between the well and the high permeability flow path network. © 2011 Elsevier B.V.

Sureshjani M.H.,IOR Research Institute | Clarkson C.R.,University of Calgary
SPE Reservoir Evaluation and Engineering | Year: 2015

Analytical methods for analyzing and forecasting production from multifractured horizontal wells completed in unconventional reservoirs are in their infancy. Among the difficulties in modeling such systems is the incorporation of fracture-network complexity as a result of the hydraulic-fracturing process. Along with a primary propped-hydraulic-fracture network, a secondary fracture network, which may or may not contain proppant, may be activated during the stimulation process, creating a "branched-fracture" network. These secondary fractures can be the result of reactivation of healed natural fractures, for example. In the current work, we develop a fully analytical enhanced-fracture-region (EFR) model for analyzing and forecasting multifractured horizontal wells with complex fracture geometry that is more-general, -rigorous, and -flexible than those previously developed. Specifically, our new model allows nonsymmetric placement of a well within its area of drainage, to reflect unequal horizontal-lateral spacing; this is a very real scenario observed in the field, particularly for the external laterals on a pad. The solutions also can be reduced to be applicable for homogeneous systems without branch fractures. In addition to the general EFR solution, we have provided local solutions that can be used to analyze individual flow regimes in sequence. We provide practical examples of the application (and sometimes misapplication) of local solutions by use of simulated and field cases. One important observation is that a negative intercept obtained from a straight line drawn through data on a square-root-of-time plot (commonly used to analyze transient linear flow) may indicate EFR behavior, but this straight line should not be interpreted as linear flow because it represents transitional flow from one linear-flow period to another. Our general EFR solution therefore provides a powerful tool to improve both forecasting and flow-regime interpretation for hydraulic-fracture/reservoir characterization. Copyright © 2015 Society of Petroleum Engineers.

Arabloo M.,IOR Research Institute | Heidari Sureshjani M.,IOR Research Institute | Gerami S.,IOR Research Institute
Journal of Natural Gas Science and Engineering | Year: 2014

Production data analysis provides key parameters to a series of reservoir engineering calculations such as reserve estimation, inflow performance calculations, and well production forecast. Although techniques of production data analysis for oil and dry gas reservoirs have advanced significantly over the past few decades, application of these techniques for analyzing production data of gas condensate reservoirs has not been fully studied despite its great practical importance. In this work, a simple yet accurate methodology is presented for reliable estimation of initial gas in place and average reservoir pressure in gas condensate reservoirs. We define new pseudopressure and material balance time functions suitable for gas condensate systems. According to our observations, a Cartesian plot of modified normalized pseudopressure versus modified material balance pseudotime of gas condensate production data yields three distinct regions. In this study we will show that the middle region is unusable and should be distinguished and removed from the analysis. The required input data are bottom hole flowing pressures, gas and condensate production rates, and constant volume depletion (CVD) test data. This study provides example analyses and establishes guidelines for the analysis and interpretation of long term production data in gas condensate reservoirs using developed Cartesian plot. © 2014 Elsevier B.V.

Heidari Sureshjani M.,IOR Research Institute | Gerami S.,IOR Research Institute | Emadi M.A.,IOR Research Institute
Oil and Gas Science and Technology | Year: 2014

In traditional material balance calculations, shut-in well pressure data are used to determine average reservoir pressure while recent techniques do not require the well to be shut-in and use instead flowing well pressure-rate data. These methods, which are known as "dynamic" material balance, are developed for single-phase flow (oil or gas) in reservoirs. However, utilization of such methods for gas-condensate reservoirs may create significant errors in prediction of average reservoir pressure due to violation of the single-phase assumption in such reservoirs. In a previous work, a method for production data analysis in gas-condensate reservoirs was developed. The method required standard gas production rate, producing gas-oil ratio, flowing well pressure, CVD data and relative permeability curves. This paper presents a new technique which does not need relative permeability curves and flowing well pressure. In this method, the producing oil-gas ratio is interpolated in the vaporized oil in gas phase (Rv) versus pressure (p) data in the CVD table and the corresponding pressure is located. The parameter pressure/two-phase deviation factor (p/ztp) is then evaluated at the determined pressure points and is plotted versus produced moles (np) which forms a straight line. The nature of this plot is such that its extrapolation to point where p/ztp = 0 will give initial moles in place. Putting initial pressure/initial two-phase deviation factor (pi/ztp,i) (known parameter) and estimated initial moles (ni) into the material balance equation, average reservoir pressure can be determined. A main assumption behind the method is that the region where both gas and condensate phases are mobile is of negligible size compared to the reservoir. The approach is quite simple and calculations are much easier than the previous work. It provides a practical engineering tool for industry studies as it requires data which are generally available in normal production operations. However, it is only applicable when average reservoir pressure approaches dew point pressure and falls below it. The methodology is validated using synthetic production data for several examples. In addition, the method is evaluated through estimation of average reservoir pressure and original gas in place from actual field data. The results show a fairly good agreement in gas in place obtained from the new method and that of volumetrically calculated value for this field. © 2013, IFP Energies nouvelles.

Heidari Sureshjani M.,IOR Research Institute
Journal of Petroleum Science and Engineering | Year: 2013

This paper presents an analytical model for modeling of matrix-fracture fluid transfer in gas systems subjected to variable fracture pressure. In this work, pseudopressure and pseudotime functions are used to linearize the matrix governing flow equation so that the constant fracture pressure solution is obtained in terms of pseudotime function. The superposition theorem is further applied on the obtained solution with respect to pseudotime to account for variable fracture pressure conditions. Knowing that using pseudotime function is an approximate technique to linearize the governing flow equation, it is observed that superposition theorem can be successfully applied with respect to this time function to predict accurate values of matrix-fracture flow rate. To avoid the use of iterative procedures for calculation of pseudotime at any point of time, a pseudotime-time relationship is developed with the aid of a material balance equation and several specific assumptions. Also, specific computational treatments are proposed to reduce the number of time steps for calculation of convolution integral and also to eliminate the error associated with calculations. A fine grid single-porosity numerical solution is prepared to verify the content of this work.© 2013.

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