Simulation of Drilling Fluid Filtrate Invasion Near an Observation Well

SPE Journal ◽  
2012 ◽  
Vol 17 (04) ◽  
pp. 1047-1055 ◽  
Author(s):  
Romain L. Chassagne ◽  
Paul S. Hammond
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Drilling Fluid ◽  
Hysteretic Behavior ◽  
Pore Network Model ◽  
Time Behavior ◽  
Observation Well ◽  
Invaded Zone ◽  
Reservoir Simulator ◽  
Observation Wells

Summary We used a commercial reservoir simulator to study, first, the dissipation of aqueous drilling fluid filtrate invasion around a cased observation well in an oil-saturated formation under the action of capillary pressure and, second, the interaction of a waterflood front with the cased well and remaining invaded zone. Hysteretic behavior of the capillary pressure and relative permeabilities is critically important to these processes and is taken into account by the use of the Carlson model, with the various bounding drainage and imbibition curves computed from a pore network model. Filtrate invasion into a hydrocarbon formation influences the readings of well-logging tools. Although this phenomenon has been known, and corrected for, for many years, uncertainty remains with regard to the long-time behavior of invasion around observation wells where no flow in or out of the formation occurs after completion, and with regard to the influence of formation wettability. We find that after sufficient time, the invaded zone dissipates completely in a water-wet formation, but some invasion always remains in the oil/mixed-wet case. Nonwetting-phase trapping, manifested through relative permeability hysteresis, is the cause. Because trapping affects the values and the endpoints of the relative permeability curves, a waterflood front passing across an observation well is more distorted in the oil/mixed-wet case. The simulation results allow us to understand how logging-tool measurements made in cased observation wells are influenced by drilling-fluid invasion and will therefore lead to improved interpretation. This study shows strong links between the wettability of the formation and the persistence of invaded zone saturation and between invaded zone saturation and the distortion of subsequent flood fronts.

Using relative permeability curves to evaluate phase trapping damage caused by water- and oil-based drilling fluids in tight-gas reservoirs

2012 ◽  
Vol 52 (1) ◽  
pp. 595 ◽  
Author(s):  
Geeno Murickan ◽  
Hassan Bahrami ◽  
Reza Rezaee ◽  
Ali Saeedi ◽  
Tsar Mitchel
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Drilling Fluid ◽  
Tight Gas ◽  
Gas Reservoirs ◽  
Tight Gas Reservoirs ◽  
Water Based ◽  
Tight Formations ◽  
Relative Permeability Curves ◽  
Tight Formation

Low matrix permeability and significant damage mechanisms are the main signatures of tight-gas reservoirs. During the drilling and fracturing of tight formations, the wellbore liquid invades the tight formation, increases liquid saturation around the wellbore, and eventually reduces permeability at the near wellbore zone. The liquid invasion damage is mainly controlled by capillary pressure and relative permeability curves. Due to high critical water saturation, relative permeability effects and strong capillary pressure, tight formations are sensitive to water invasion damage, making water blocking and phase trapping damage two of the main concerns with using a water-based drilling fluid in tight-gas reservoirs.Therefore, the use of an oil-based mud may be preferred in the drilling or fracturing of a tight formation. Invasion of an oil filtrate into tight formations, however, may result in the introduction of an immiscible liquid-hydrocarbon drilling or completion fluid around the wellbore, causing the entrapment of an additional third phase in the porous media that would exacerbate formation damage effects. This study focuses on phase trapping damage caused by liquid invasion using a water-based drilling fluid in comparison with the use of an oil-based drilling fluid in water-sensitive, tight-gas sand reservoirs. Reservoir simulation approach is used to study the effect of relative permeability curves on phase trap damage, and the results of laboratory experiments of core flooding tests in a West Australian tight-gas reservoir are shown, where the effect of water injection and oil injection on the damage of core permeability are studied. The results highlight the benefits of using oil-based fluids in drilling and fracturing of tight-gas reservoirs in terms of reducing skin factor and improving well productivity.

A Pore-Network-Modeling Approach To Predict Petrophysical Properties of Diatomaceous Reservoir Rock

2007 ◽  
Vol 10 (06) ◽  
pp. 597-608 ◽  
Author(s):  
Liping Jia ◽  
Cynthia Marie Ross ◽  
Anthony Robert Kovscek
Keyword(s):  
Multiphase Flow ◽  
Capillary Pressure ◽  
Network Model ◽  
Relative Permeability ◽  
Oil Recovery ◽  
Pore Network ◽  
Reservoir Rock ◽  
Pore Network Model ◽  
Rock Types ◽  
Capillary Pressure Curves

Summary A 3D pore-network model of two-phase flow was developed to compute permeability, relative permeability, and capillary pressure curves from pore-type, -size, and -shape information measured by means of high-resolution image analysis of diatomaceous-reservoir-rock samples. The diatomite model is constructed using pore-type proportions obtained from image analysis of epoxy-impregnated polished samples and mercury-injection capillary pressure curves for diatomite cores. Multiple pore types are measured, and each pore type has a unique pore-size and throat-size distribution that is incorporated in the model. Network results present acceptable agreement when compared to experimental measurements of relative permeability. The pore-network model is applicable to both drainage and imbibition within diatomaceous reservoir rock. Correlation of network-model results to well log data is discussed, thereby interpolating limited experimental results across the entire reservoir column. Importantly, our method has potential to predict the petrophysical properties for reservoir rocks with either limited core material or those for which conventional experimental measurements are difficult, unsuitable, or expensive. Introduction Model generation for reservoir simulation requires accurate entering of physical properties such as porosity, permeability, initial water saturation, residual-oil saturation, capillary pressure functions, and relative permeability curves. These functions and parameters are necessary to estimate production rate and ultimate oil recovery, and thereby optimize reservoir development. Accurate measurement and representation of such information is, therefore, essential for reservoir modeling. Relative permeability and capillary pressure curves are the most important constitutive relations to represent multiphase flow. Often, it is difficult to sample experimentally the range of relevant multiphase-flow behavior of a reservoir. In addition to the availability of rock samples, measurements are frequently time consuming to conduct, and conventional techniques are not suitable for all rock types (Schembre and Kovscek 2003). It is impossible, therefore, to measure all the unique relative permeability functions of different reservoir-rock types and variations within a rock type. This lack of constitutive information limits the accuracy of reservoir simulators to predict oil recovery. Simply put, other available data must be queried for their relevance to multiphase flow and must be used to interpret the available relative permeability and capillary pressure information.

History Matching Heterogeneous Coreflood of CO2/Brine by Use of Compositional Reservoir Simulator and Geostatistical Approach

SPE Journal ◽  
2014 ◽  
Vol 20 (02) ◽  
pp. 267-276 ◽  
Author(s):  
Xianhui Kong ◽  
Mojdeh Delshad ◽  
Mary F. Wheeler
Keyword(s):  
High Resolution ◽  
Capillary Pressure ◽  
Relative Permeability ◽  
Mean Value ◽  
Heterogeneous Distribution ◽  
Compositional Model ◽  
The Core ◽  
The Mean ◽  
Relative Permeability Curves ◽  
Reservoir Simulator

Summary Numerical modeling and simulation are essential tools for developing a better understanding of the geologic characteristics of aquifers and providing technical support for future carbon dioxide (CO2) storage projects. Modeling CO2 sequestration in underground aquifers requires the implementation of models of multiphase flow and CO2 and brine phase behavior. Capillary pressure and relative permeability need to be consistent with permeability/porosity variations of the rock. It is, therefore, crucial to gain confidence in the numerical models by validating the models and results by use of laboratory and field pilot results. A published CO2/brine laboratory coreflood was selected for our simulation study. The experimental results include subcore porosity and CO2-saturation distributions by means of a computed tomography (CT) scanner along with a CO2-saturation histogram. Data used in this paper are all based on those provided by Krause et al. (2011), with the exception of the CT porosity data. We generated a heterogeneous distribution for the porosity but honoring the mean value provided by Krause et al. (2011). We also generated the permeability distribution with the mean value for the whole core given by Krause et al. (2011). All the other data, such as the core dimensions, injection rate, outlet pressure, temperature, relative permeability, and capillary pressure, are the same as those in Krause et al. (2011). High-resolution coreflood simulations of brine displacement with supercritical CO2 are presented with the compositional reservoir simulator IPARS (Wheeler and Wheeler 1990). A 3D synthetic core model was constructed with permeability and porosity distributions generated by use of the geostatistical software FFTSIM [Jennings et al. (2000)], with cell sizes of 1.27×1.27×6.35 mm. The core was initially saturated with brine. Fluid properties were calibrated with the equation-of-state (EOS) compositional model to match the measured data provided by Krause et al. (2011). We used their measured capillary pressure and relative permeability curves. However, we scaled capillary pressure on the basis of the Leverett J-function (Leverett 1941) for permeability, porosity, and interfacial tension (IFT) in every simulation grid cell. Saturation images provide insight into the role of heterogeneity of CO2 distribution in which a slight variation in porosity gives rise to large variations in CO2-saturation distribution in the core. High-resolution numerical results indicated that accurate representation of capillary pressure at small scales was critical. Residual brine saturation and the subsequent shift in the relative permeability curves showed a significant impact on final CO2 distribution in the core.

Assessment and Inclusion of Capillary Pressure/Relative Permeability Hysteresis Effects in Downhole Water Sink (DWS) Well Technology for Water Coning Control

2001 ◽  
Author(s):  
Solomon O. Inikori ◽  
Andrew K. Wojtanowicz
Keyword(s):  
Capillary Pressure ◽  
Relative Permeability ◽  
Oil Production ◽  
Well Performance ◽  
Water Drainage ◽  
Well Design ◽  
Water Coning ◽  
Capillary Pressures ◽  
Reservoir Simulator ◽  
Downhole Water Sink

Abstract The objective of this study is to assess the effects of capillary pressures and relative permeability hysteresis on the performance of wells using the downhole water sink (DWS) technology for water coning control. In the study a commercial reservoir simulator has been adopted to evaluate well performance under conditions of stabilized oil production/water drainage rates for various combinations of these rates. Operational domain of water-free oil production, Inflow Performance Window (IPW), was used to quantify the effects of capillary pressure transition zone and relative permeability hysteresis on the water coning - control performance of DWS wells. Field data from wells in Canada, West Africa and Louisiana exhibiting severe problems of water coning were used in this study. The simulation results show that the basic concept of the DWS is unchanged by the inclusion of capillary pressure and relative permeability hysteresis. However, these effects may cause considerable reduction in the size of the water-free oil production domain and lead to increase in water production. The results also indicate that, for the same reservoir, converting conventional wells with prior water coning history to DWS application would not be as beneficial as DWS completions on new wells. Thus the effect of drainage-imbibition relative permeability hysteresis should be included in the DWS well design practice.

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