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Results
Abstract Reaching dew-point conditions upon depletion in a near-critical gas reservoir results in the precipitation of a liquid hydrocarbon phase or condensate dropout. Condensate dropout is usually immobile and impairs the flow of the other phases, adversely affecting reservoir productivity and ultimate recovery in this type of gas reservoirs. In the case of fissured reservoirs, the high-conductivity channels supplied by the fracture network will be prone to faster depletion upon fluid withdrawal. Condensate dropout would then occur in the fracture network first and then in the external edges of the matrix blocks. Even though condensate dropout in the fracture may have considerable mobility, this is not the case for the liquid formed at the external portions of the matrix. In this scenario, liquid buildup will hinder the flow of hydrocarbons from the inner portions of the matrix blocks and severely obstruct their recovery. This study aims at the numerical tracking of the liquid barrier, which requires a fine discretization of the inner portions of the matrix blocks, and the analysis of the interplay between the condensate barrier and hydrocarbon flow within the surrounding matrix/fracture system. While traditional wisdom dictates that reservoir condensate dropout is undesirable because this valuable condensate may be completely lost to the formation, this study analyzes if the situation is even worse for the case of fissured systems. In addition to low surface condensate recoveries, condensate appearance in fissured systems may also indicate that the inner-block gas stored in the matrices—where the bulk of the reservoir storage resides—might be also unrecoverable. In this study, guidelines for the development of this class of reservoirs are presented by identifying the controlling parameters of system behavior and ultimate recovery and analyzing the depletion characteristics of near critical fluids in fissured systems. Introduction Up to recently, the work of Castelijns and Hagoort (1984) was the only study dedicated to the analysis of retrograde condensation in naturally-fractured gas-condensate reservoirs. Their analysis was applied to assess the potential of condensate recovery in the Waterton reservoir (Alberta, Canada) and it was restricted to the properties of the reservoir under consideration. In their study, analytical flow models were presented to calculate the possibility of recovering part of the condensate by gravity drainage. In the present study, we have concentrated our efforts in the understanding of condensate build-up within the matrix at saturations below critical and its interplay with Fickian-controlled diffusion, with special emphasis in the limiting case where matrix permeabilities are extremely low. In such cases, flow hindrance due to the presence of the condensate is exacerbated. When a naturally-fractured reservoir stores a retrograde gas, the initial depletion stage of these systems can be represented with the illustration presented in Figure 1. The fracture-network is prone to faster depletion, and, upon the establishment of the favorable gradients, the matrix blocks start discharging fluids to the fractures, as shown in the same figure. In a gas-condensate system, depletion upon fluid withdrawal results in condensate dropout once the system pressure falls below dew-point conditions. Because they are subjected to faster depletion, the fracture network and the external edges of the matrix blocks will be the first to host condensate in the system. This situation is illustrated in Figure 2. If the matrix blocks are extremely tight, the inner portion of the matrix blocks may not "feel" the pressure change until a later depletion stage. Even if fracture condensate had considerable mobility, matrix condensate is expected to be nearly immobile. Therefore, appearance of condensate on the matrix block faces further constrains gas withdrawal from the inner parts. Consequently, condensate may never be formed in the inner-most portion of the matrix and the hydrocarbon gas located in the deeper portions of the matrix blocks may not be easily recovered.
- North America > United States (0.68)
- North America > Canada > Alberta (0.24)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Naturally-fractured reservoirs (1.00)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Gas-condensate reservoirs (1.00)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
Abstract An Artificial Neural Network (ANN) was designed and tested in the present study to examine the correlation between permeability estimations and porous medium properties, such as porosity, specific surface area, and irreducible water saturation. The network developed in this work is a predictive tool that uses soft computing techniques to estimate absolute permeability of carbonate reservoirs. The Artificial Neural Network toolbox of MATLAB® R2006b and the Feed Forward Error Back Propagation methodology were used in the construction of the network. Carbonate reservoir field data presented in the literature were utilized in the training, testing, and validation of the proposed model. The present study indicates that ANN generated permeability values are consistent with those obtained from core analysis. Results from this study confirm the complex relationship among permeability, porosity, specific surface area and irreducible water saturation of carbonate reservoirs, and suggest that variations in specific surface area affect the magnitude of irreducible water saturations, thus creating an apparent dependence of permeability on irreducible water saturation. Additional observations support a direct relationship between porosity and permeability, and an inverse relationship between specific surface area and permeability. Introduction Porosity-permeability relationships are of great importance for the reservoir engineer because of the difficulties and uncertainties associated with direct permeability interpretations from well-log data. Accurate permeability predictions provide engineers with the ability to design and manage efficient processes in the development of oil and gas fields. Although it is generally accepted that permeability is closely related to porosity, their relationship cannot be captured by a simple expression. Absolute permeability is a dynamic flow property, while porosity is a measure of the storage capacity of a rock, a static rock property. The absolute permeability of a porous medium varies with grain size, sorting, cementing, direction, and location; thus the scatter quality of permeability plots. A wide range of permeability correlations using pore- and field-scale models are presented in the literature 1–3. Starting with the seminal works by Kozeny 4 and Carman 5, many different correlations have been proposed between porosity and permeability. The Kozeny-Carman equation was developed for a porous medium represented by a bundle of uniform capillary tubes and introduces a direct dependence between porosity and permeability, while accounting for specific surface area and tortuosity as a measure of flow resistance. eq. (1) For unconsolidated porous media with variable particle size, Panda and Lake 6 propose a modification of the Kozeny-Carman equation to express permeability in terms of particle-size distribution characteristics and the bulk physical rock properties. They found reasonable agreement between predicted and experimental permeability, relying on appropriate estimations of surface area, and demonstrated the modest impact of sorting on the quality of their predictions. With respect to sorting, porosity tends to increase for perfectly sorted media and decrease as sorting becomes poorer 7, thus affecting permeability.
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- North America > United States > Colorado > Uinta Basin (0.99)
- North America > Canada > Nova Scotia > North Atlantic Ocean > Scotian Basin > Sable Basin > Sable Project > Venture Field (0.99)
Abstract Successful design and implementation of a miscible gas injection project depends upon the minimum miscibility pressure (MMP) and other factors such as reservoir and fluid characterization. The experimental methods available for determining MMP are both costly and time consuming. Therefore, the use of correlations that prove to be reliable for a wide range of fluid types would likely be considered acceptable for preliminary screening studies. This work includes a comparative evaluation of MMP correlations and thermodynamic models using an equation of state by PVTsim 1 software. We observed that none of the evaluated MMP correlations studied in this investigation is sufficiently reliable. EOS-based analytical methods seemed to be more conservative in predicting MMP values. Following an acceptable estimate of MMP, several compositional simulation runs were conducted to determine the sensitivity of the oil recovery to variations in injection pressure (at pressures above, equal to and below the estimated MMP), stratification and mobility ratio parameters in miscible and immiscible gas injection projects. Simulation results indicated that injection pressure was a key parameter that affects oil recovery to a high degree. MMP determined to be the optimum injection pressure. Stratification and mobility ratio could also affect the recovery efficiency of the reservoir in a variety of ways. Introduction Through the past decades, miscible displacement processes have been developed as a successful oil recovery method in many reservoirs. The successful design and implementation of a gas injection project depends on the favorable fluid and rock properties. The case studies using Eclipse 2 compositional simulator considered the effect of key parameters, such as injection pressure, stratification and mobility ratio on the performance recovery in miscible and immiscible flooding of the reservoir. However, accurate estimation of the minimum miscibility pressure is important in conducting numerous simulation runs. MMP is the minimum miscibility pressure which defines whether the displacement mechanism in the reservoir is miscible or immiscible. Thermodynamic models using an equation of state and appropriate MMP correlations were used in determining the MMP. Compositional simulation runs determined the sensitivity of the oil recovery to the variations in above mentioned parameters. Significant increase in oil recovery was observed when interfacial tension dependent relative permeability curves were used. These relative permeability curves provide an additional accounting for miscibility by using a weighted average between fully miscible and immiscible relative permeability curves. The local interfacial tension determines the interpolation factor which is used in obtaining a weighted average of immiscible and miscible (straight line) relative permeabilities. Simulation runs were performed at pressures below, equal to, and greater than estimated MMP for reservoir fluid/ injection gas system. Oil recovery was greatest when miscibility achieved. To investigate the effect of stratification on the performance recovery of the reservoir, the base relative permeability of two layers changed. Location of the high permeable layer (up or bottom layer) in the stratified reservoir greatly influenced the efficiency of the reservoir. Understanding the effect of interfacial tension and adverse mobility ratio on the efficiency of the gas injection project was the last case study. Injection gas and reservoir fluid compositions differed in such a way to have interfacial tension and mobility dominated mechanism. To investigate the effect of interfacial tension water was considered as a fluid with much higher surface tension values with the oil. Lower surface tension values between rich gas and reservoir fluid (interfacial tension dominated) made gas injection project a more competitive recovery method than waterflooding. In mobility dominated displacement mechanism (lean gas/reservoir fluid system) the viscous instabilities were more important than the interfacial tension effect. For this case, waterflooding with favorable mobility ratio resulted in higher oil recoveries.
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 186 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- Africa > Middle East > Libya > Wadi al Hayat District > Murzuq Basin > Block NC 115 > I&R Fields > R Field > Mamouniyat Formation (0.99)
- Reservoir Description and Dynamics > Reservoir Fluid Dynamics > Flow in porous media (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Gas-injection methods (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery > Chemical flooding methods (1.00)
- Reservoir Description and Dynamics > Fluid Characterization > Fluid modeling, equations of state (1.00)
Abstract A rapid and an effective reservoir simulation model was built based on limited information. 3D seismic impedance, two exploratory wells' log interpretation, a core data, and a well test consisting of an isochronal test and, several months later, an extended flow followed by long build up test were basic available data for this field. The main objective of this study is to estimate recoverable reserve with or without hydraulic fracturing in Mulichinco formation at the Paso Del Indio Field. Material balance and decline curve analyses have important limitations to estimate ultimate recoverable reserves in the tight gas reservoirs. Well types that are derived from the conceptual simulation models do not reflect the effective drainage area or permeability heterogeneity in the field. A representative permeability in well spacing area should be averaged harmonically or geometrically. In order to estimate the ultimate recoverable reserves in the tight gas reservoirs, permeability heterogeneity or the effective available drainage area to hydraulic fractures should be simulated effectively. Relatively small changes in permeability can results in unsuccessful fracture design and in uneconomical flow rates. A very quick and effective simple reservoir simulation model was established to estimate recoverable reserves rather than using conventional volumetric, material balance, and decline curve analysis in tight gas reservoirs. Not having any production histories, well test information was used very successfully as history matching information to validate the geological, petrophysical, and PVT models. Introduction The Mulichinco Formation is a mainly clastic unit broadly developed in the Lower Cretaceous of the Neuquén Basin. The unit is composed of up to 500 meters of continental to shallow marine deposits having a clear transgressive tendency. In central basin positions the Mulichinco Formation is one of the main hydrocarbon reservoirs, with petrophysical properties largely controlled by facies, stratigraphy and structural position 1. Reservoir properties are very heterogeneous, areally as well as vertically due to stratigraphic trapping and diagenesis. Tight gas reservoirs are more heterogeneous than high permeability reservoirs. Permeability variations in gas bearing formation, hydraulic fracturing properties, and fracture connectivity to formation are main parameters for the gas rates and ultimate recoverable reserves estimation. Applying classical reservoir engineering techniques to tight gas reservoirs has important limitations. Volumetric calculations are usually intended to overestimate original gas in place due to constant reservoir property assumption. Material balance and decline curve analysis have serious drawbacks to estimate ultimate recoverable reserves in tight gas reservoirs. Obtaining average representative reservoir pressure during testing, establishing boundary dominated flow, or establishing constant drainage area in tight gas reservoirs is almost impossible in the early life of the project. Many studies 2–4 have been conducted to modify straight line material balance (P/z) analyses for the curved nonlinear behavior reservoir in order to estimate ultimate recoverable reserves. Quantitive interpretation of the curved lines does not reflect reservoir permeability heterogeneity and hydraulic fracture properties. For optimum well spacing, optimal drainage aspect ratio, and fracture design, numerous numerical and analytical models 5–9 for the elliptical flow were developed for tight gas sands. Due to very strong variation of low permeabilities and capillary forces in a very short space domain, initial water saturation distributions in gas bearing formation also change from typical 0.3 to 0.75 values. In tight gas reservoirs, well productivities are greatly impacted from water blocking due to strong capillary forces and condensate drop out in an elliptic flow region, even when the liquid drop out is less than 1%.
- South America > Argentina > Neuquén Province > Neuquén (1.00)
- North America > United States > Texas (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.69)
- Geology > Geological Subdiscipline > Stratigraphy (0.54)
- Geophysics > Seismic Surveying (1.00)
- Geophysics > Borehole Geophysics (1.00)