Milad Saidian

Qualitative and quantitative reservoir bitumen characterization: A core to log correlation methodology

AbstractReservoir bitumen is a highly viscous, asphaltene-rich hydrocarbon that can have important effects on reservoir performance. Discriminating between producible oil and reservoir bitumen is critical for recoverable hydrocarbon volume calculations and production planning, yet the lack of resistivity contrast between the two makes it difficult, if not impossible, to make such differentiation using conventional logs. However, the nuclear magnetic resonance (NMR) response in bitumen-rich zones is dominated by short transverse relaxation times (T2) and a low apparent fluid hydrogen index (HIapp), providing an opportunity to identify the presence of reservoir bitumen. Therefore, NMR logging technology becomes crucial in the characterization of reservoirs in which the presence of bitumen may be of concern. We used NMR and other log data to identify and quantify the occurrence of reservoir bitumen in a carbonate reservoir. A thorough petrophysical evaluation was performed using a full suite of logs, formati...

Effect of Mineralogy on NMR, Sonic, and Resistivity: A Case Study of the Monterey Formation

The Monterey formation has a wide variety of lithologies (diatomites and diagenetically derived cherts, porcelanite, organic-rich mudstones, phosphatic, and carbonate rocks) representing the effect of tectonic, oceanographic, and climatic events. Although the formation has been studied extensively, the effects of lithology on saturation and pore size distributions are still poorly understood. This lack of understanding stems partly from a paucity of data and partly because models built for conventional siliciclastic reservoirs are not applicable. In this study we investigate the differences between biogenic and detrital silica as well as effects of additional influx of clay and carbonate material in the biogenic lithology. Recognizing such differences can help better analyze and interpret NMR, sonic, porosity, and resistivity logs. Our combined laboratory and well log data analysis shows how mineralogy and clay content affect velocities and pore size distributions: 1. With increasing carbonate content, Pand S-wave velocities (Vp, Vs, respectively) increase as compared to silicate-rich rocks. 2. Mineralogical surface relaxivity variations are evaluated by combining mercury intrusion and low-field Nuclear Magnetic Resonance (NMR) data. 3. Considerable amount of porosity is trapped in small pores in the biogenic quartz phase rocks. 4. Pore size distributions in carbonateor dolomite-rich rocks are distinct from siliceous rocks, and correlate well with higher (above 35%) oil/water ratios. 5. High detrital clay content identified by high Thorium content in spectral gamma ray logs masks the resistivity response due to an increase in neutron porosity (NPHI) and decrease in resistivity.

Chapter 7: A Comparison of Measurement Techniques for Porosity and Pore Size Distribution in Shales (Mudrocks): A Case Study of Haynesville, Eastern European Silurian, Niobrara, and Monterey Formations

Abstract Porosity and pore size distribution (PSD) are required to calculate reservoir quality and volume. Numerous inconsistencies have been reported in measurements of these properties in shales (mudrocks). We investigate these inconsistencies by evaluating the effects of fine grains, small pores, high clay content, swelling clay minerals and pores hosted in organic content. Using mudrocks from the Haynesville, Eastern European Silurian, Niobrara, and Monterey formations, we measured porosity and pore or throat size distribution using subcritical nitrogen (N2) gas adsorption at 77.3 K, mercury intrusion, water immersion, and helium porosimetry based on Gas Research Institute standard methodology. We used scanning electron microscope (SEM) images to understand the pore structure at a microscopic scale. We separated the samples from each formation into groups based on their clay and total organic carbon (TOC) contents and further investigated the effects of geochemical and mineralogical variations on porosity and PSD. We find that differences in the porosity and PSD measurement techniques can be explained with thermal maturity, texture, and mineralogy, specifically clay content and type and TOC variations. We find that porosity and PSD measurement techniques can provide complementary information within each group provided the comparison is made between methods appropriate for that group. Our intent is to provide a better understanding of the inconsistencies in porosity measurements when different techniques are used.

Rock Typing of Tight Gas Sands: A Case Study in Lance and Mesaverde Formations From Jonah Field

The Jonah field is one of the biggest tight gas sand fields in the Green River basin. Production profiles from its deeper sections show high liquid hydrocarbons close to the Pinedale anticline, especially in Mesaverde and Lance formations. To assess the potential of condensate production, new approaches for rock classification are needed to differentiate between discontinuous sandstone layers and the interbedded siltstones. A gamma ray cut off of 75 API has been defined to distinguish between sandstone and siltstone in logs and core samples in Lance and Mesaverde formations. Significant variation of porosity and permeability occurs within the sandstone zones. This variation warrants new rock typing approaches. We present rock typing for tight sandstones and siltstones with an understanding of petrophysical properties such as pore structure, porosity, permeability, and cementation. We studied 94 samples from the Mesaverde and Lance Formations with lithologies varying from clean sandstone to shale. X-ray diffraction (XRD) mineralogy, mercury injection capillary pressure (MICP), helium porosity and permeability were measured for all samples. NMR transverse relaxation times (T2) at 2 MHz were also measured for 10 water saturated samples. Nitrogen adsorption was performed on 11 samples from Mesaverde formation to determine pore volume and pore size distribution. MICP data are used to subdivide rocks into three groups based on pore throat size distribution: reservoir sandstones, non-reservoir sandstone and siltstone/mudstone. Dominant pore throat size for reservoir and non-reservoir sandstones are 400 and 100 nm, respectively. In order to apply pore throat size rock typing to downhole measurements, correlation between NMR pore size and MICP throat size is used. Pore size from NMR demonstrated equivalent behavior to pore throat size from MICP. The logarithmic mean values of T2 transverse relaxation times for reservoir, non-reservoir sandstone and siltstone/mudstone are 22.2 ms, 3.4 ms and 0.29 ms, respectively. Clear separation of reservoir sandstone, non-reservoir sandstone and siltstone is also seen based on pressure dependency of ultrasonic compressional and shear velocities during initial pressure loading. Reservoir sandstone demonstrates the highest compressibility. In addition, siltstone and mudstone were separated based on log differential pore volume distribution from N2 adsorption data. Based on pore size distribution data, four main rock types are identified in Lance and Mesaverde formations in Jonah field. Rock typing based on gamma ray and porosity logs can be considered as rock classification of end members. To capture transitional behavior in between end members, pore size distribution is needed in logging application. Since NMR T2 distribution show similar spectra to MICP throat size distribution, the rock typing technique can be applied using NMR log data. Separation of mudstone from siltstone can be used for identification of shale end points in log data.