Reza Rezaee

CO2‐wettability of caprocks: Implications for structural storage capacity and containment security

Structural trapping, the most important CO2 geostorage mechanism during the first decades of a sequestration project, hinges on the traditional assumption that the caprock is strongly water wet. However, this assumption has not yet been verified; and it is indeed not generally true as we demonstrate here. Instead, caprock can be weakly water wet or intermediate wet at typical storage conditions; and water wettability decreases with increasing pressure or temperature. Consequently, a lower storage capacity can be inferred for structural trapping in such cases.

The Importance of Geochemical Parameters and Shale Composition on Rock Mechanical Properties of Gas Shale Reservoirs: a Case Study From the Kockatea Shale and Carynginia Formation From the Perth Basin, Western Australia

Evaluation of the gas shale mechanical properties is very important screening criteria for determining the potential intervals for hydraulic fracturing and as a result in gas shale sweet spot mapping. Young’s modulus and Poisson’s ratio are two controlling mechanical properties that dictate the brittleness of the gas shale layers. These parameters can be determined in the laboratory by testing the rock sample under different conditions (static method) or can be calculated using the well-logging data including sonic and density log data (dynamic method). This study investigates the importance of the shale composition and geochemical parameters on the Young’s modulus and Poisson’s ratio using log data. The data set of this study is coming from five different wells targeting the Kockatea Shale and Carynginia formation, two potential gas shale formations in the Perth Basin, Western Australia. The results show that converse to the common idea the effect of organic matter quantity and maturity on the rock mechanical properties of the gas shale reservoirs is not so much prominent, while the composition of the rock has an important effect on these properties. Considering the weight percentage of shale composition and organic matter quantity it could be concluded that effect of these parameters on rock mechanical properties is dependent on their weight contribution on the shale matrix. As well as effect of thermal maturity on the shale matrix and consequently on the rock mechanical properties of the shales is dependent on the organic matter content itself; therefore, obviously with a low organic matter content thermal maturity has no prominent effect on the brittleness as well.

Pore-Facies as a tool for incorporation of small scale dynamic information in integrated reservoir studies

In this study, the quantification and incorporation of pore geometry, a qualitative parameter, and a source of dynamic information, will be demonstrated in the integrated reservoir studies. To quantify pore geometry, mercury injection capillary pressure (MICP) curves have been exploited. For each MICP curve, 20 parameters were derived and multi-resolution graph-based clustering was applied to classify the curves into nine representative distinct clusters. The number of clusters was determined based on petrography and cluster analysis. The quantified pore geometry in terms of discrete variable has been called pore-facies, and like electro-facies and litho-facies could be used in facies modelling and rock typing phases of an integrated study. The dependence of dynamic reservoir rock properties on pore geometry makes the pore-facies an interesting and powerful approach for incorporation of small-scale dynamic data into a reservoir model. A comparison among various facies definitions proved that neither litho-facies nor electro-facies is capable of characterizing dynamic rock properties, and the best results were achieved by the pore-facies method. Based on this study, it is recommended that for facies analysis in reservoir modelling, methods based on pore characteristics such as pore-facies, introduced in this paper, be used rather than traditional facies that rely on matrix properties. The next generation of the reservoir models which incorporate pore-facies-based rock types will provide a basis for more accurate static and dynamic models, a narrower range of uncertainty in the models, and a better prediction of reservoir performance.

Electrofacies in gas shale from well log data via cluster analysis: A case study of the Perth Basin, Western Australia

Identifying reservoir electrofacies has an important role in determining hydrocarbon bearing intervals. In this study, electrofacies of the Kockatea Formation in the Perth Basin were determined via cluster analysis. In this method, distance data were initially calculated and then connected spatially by using a linkage function. The dendrogram function was used to extract the cluster tree for formations over the study area. Input logs were sonic log (DT), gamma ray log (GR), resistivity log (IND), and spontaneous potential (SP). A total of 30 reservoir electrofacies were identified within this formation. Integrated geochemical and petrophysics data showed that zones with electrofacies 3, 4, 9, and 10 have potential for shale gas production. In addition, the results showed that cluster analysis is a precise, rapid, and cost-effective method for zoning reservoirs and determining electrofacies in hydrocarbon reservoirs.

Permeability Prediction from Mercury Injection Capillary Pressure: An Example from the Perth Basin, Western Australia

For shale gas reservoirs, permeability is one of the most important—and difficult—parameters to determine. Typical shale matrix permeabilities are in the range of 10 microdarcy–100 nanodarcy, and are heavily dependent on the presence of natural fractures for gas transmissibility. Permeability is a parameter used to measure the ability of a rock to convey fluid. It is directly related to porosity and depends on the pore geometry features, such as tortuosity, pore shape and pore connectivity. Consequently, rocks with similar porosity can exhibit different permeability. Generally, permeability is measured in laboratories using core plugs. In some cases, however, it is difficult to obtain suitable core plugs. In these instances, other approaches can be used to predict permeability, which are chiefly based on mathematical and theoretical models. The approach followed in this peer-reviewed paper is to correlate permeability with capillary pressure data from mercury injection measurements. The theoretical and empirical equations, introduced in the literature for various conventional and unconventional reservoir rocks, have been used to predict permeability. Estimated gas shale permeabilities are then compared with results from transient and steady state methods on small pieces of rocks embedded in a resin disk. The study also attempts to establish a suitable equation that is applicable to gas shale formations and to investigating the relationship between permeability and porosity.

Evaluation of Damage Mechanisms and Skin Factor in Tight Gas Reservoirs

Tight gas reservoirs normally have production problems due to very low matrix permeability and significant damage during well drilling, completion, stimulation and production. Therefore, they may not flow gas at optimum rates without advanced production improvement techniques. The main damage mechanisms and the factors that have significant influence on total skin factor in tight gas reservoirs include mechanical damage to formation rock, plugging of natural fractures by mud solid particles invasion, relative permeability reduction around wellbore as a result of filtrate invasion, liquid leak-off into the formation during fracturing operations, water blocking, skin due to wellbore breakouts, and the damage associated with perforation. Drilling and fracturing fluids invasion mostly occurs through natural fractures and may also lead to serious permeability reduction in the rock matrix that surrounds the natural or hydraulic fractures.

Characterizing natural fractures productivity in tight gas reservoirs

Tight formations normally have production problems mainly due to very low matrix permeability and various forms of formation damage that occur during drilling completion and production operation. In naturally fractured tight gas reservoirs, gas is mainly stored in the rock matrix with very low permeability, and the natural fractures have the main contribution on total gas production. Therefore, identifying natural fractures characteristics in the tight formations is essential for well productivity evaluations. Well testing and logging are the common tools employed to evaluate well productivity. Use of image log can provide fracture static parameters, and welltest analysis can provide data related to reservoir dynamic parameters. However, due to the low matrix permeability and complexity of the formation in naturally fractured tight gas reservoirs, welltest data are affected by long wellbore storage effect that masks the reservoir response to pressure change, and it may fail to provide dual-porosity dual-permeability models dynamic characteristics such as fracture permeability, fracture storativity ratio and interporosity flow coefficient. Therefore, application of welltest and image log data in naturally fractured tight gas reservoirs for meaningful results may not be well understood and the data may be difficult to interpret. This paper presents the estimation of fracture permeability in naturally fractured tight gas formations, by integration of welltest analysis results and image log data based on Kazemi’s simplified model. Reservoir simulation of dual-porosity and dual-permeability systems and sensitivity analysis are performed for different matrix and fracture parameters to understand the relationship between natural fractures parameters with welltest permeability. The simulation results confirmed reliability of the proposed correlation for fracture permeability estimation. A field example is also shown to demonstrate application of welltest analysis and image log data processing results in estimating average permeability of natural fractures for the tight gas reservoir.

Effect of Drilling Fluid (Water-Based vs Oil-Based) on Phase Trap Damage in Tight Sand Gas Reservoirs

Tight gas reservoirs normally have production problems due to very low matrix permeability and different damage mechanisms during drilling, completion and stimulation operations. Therefore they may not produce gas at commercial rates without production optimization and advanced completion techniques. Tight formations have small pore size with significant capillary pressure energy suction that imbibes and holds liquid in the capillary pores. Leak off of liquid into formation damages near wellbore permeability due to phase trap damage and clay swelling, and it can significantly reduce well productivity even in hydraulically fractured tight gas reservoirs. This study presents evaluation of damage mechanisms associated with water invasion and phase trapping in tight gas reservoirs. Single well reservoir simulation is performed based on typical West Australian tight gas formation data, in order to understand how water invasion into formation affects well production performance in both non-fractured and hydraulically fractured tight gas reservoirs. A field example of hydraulic fracturing in a West Australian tight gas reservoir is shown and the results are analysed in order to show importance of damage control in hydraulic fracturing stimulation of low permeability sand formations.

Measuring Elastic Properties to determine the influence of TOC on Synthetic Shale Samples

This paper describes the factors that control elastic properties of organic shale, which is crucial for exploration and successful gas production from unconventional reservoirs. Mechanical and dynamic elastic properties are main shale characteristics that are not yet well understood as there have been a limited number of investigations involving organic rich shale samples. Synthetic shale core samples whose clay mineralogy, non-clay mineral content and Total Organic Carbon (TOC) content are known can be used to study variations of elastic parameters in a controlled experimental environment including in-situ stress conditions. More than 20 synthetic shale samples were created for our investigations under reservoir stress conditions with different mineral composition and TOC percentage. Ultrasonic transducers were used to measure body wave velocities, which were then used to calculate the elastic properties of different shale samples. The results demonstrate that P- and S-wave velocities vary with changing TOC under isotropic stress conditions. It is shown that the velocities of P-and S-waves are inversely proportional to TOC content. In addition, the increase in the TOC produced a decrease in density from approximately 2.4 g/cc to 2.15 g/cc and increase in porosity from approximately 16% to 20%.

Integration of Core Data, Well Logs and Seismic Attributes for Identification of the Low Reservoir Quality Units with Unswept Gas in the Carbonate Rocks of the World's Largest Gas Field

Tight zones of the gas bearing Kangan and Dalan formations of the South Pars gas field contain a considerable amount of unswept gas due to their low porosity, low permeability and isolated pore types. The current study, integrates core data, rock elastic properties and 3D seismic attributes to delineate tight and low-reservoir-quality zones of the South Pars gas field. In the first step, the dynamic reservoir geomechanical parameters were calculated based on empirical relationships from well log data. The log-derived elastic moduli were validated with the available laboratory measurements of core data. Cross plots between estimated porosity and elastic parameters based on Young’s modulus indicate that low porosity zone coincide with high values of Young’s module. The results were validated with petrographic studies of the available thin sections. The core samples with low porosity and permeability are correlated with strong rocks with tight matrix frameworks and high elastic values. Subsequently, rock elastic properties including Young’s modulus and Poisson’s ratio along with porosity were estimated by using neural networks from a collection of 3D post-stack seismic attributes, such as acoustic impedance (AI), instantaneous phase of AI and apparent polarity. Distinguishing low reservoir quality areas in pay zones with unswept gas is then facilitated by locating low porosity and high elastic modulus values. Anhydrite zones are identified and eliminated as non-pay zones due to their characterization of zero porosity and high Young modulus values. The methodology described has applications for unconventional reservoirs more generally, because it is able to distinguish low porosity and permeability zones that are potentially productive from those unprospective zones with negligible reservoir quality.