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Results
Using Digital Rock Modeling to Estimate Permeability and Capillary Pressure from NMR and Geochemical Logs
Zhang, Hao (Baker Hughes Incorporated) | Yuan, Peng (Baker Hughes Incorporated) | Wu, Jianghui (Baker Hughes Incorporated) | Mezzatesta, Alberto (Baker Hughes Incorporated) | Jin, Guodong (Baker Hughes Incorporated) | Satti, Rajani (Baker Hughes Incorporated) | Koliha, Nils (Exa Corporation) | Bautista, Juan (Exa Corporation) | Crouse, Bernd (Exa Corporation) | Freed, David (Exa Corporation)
Abstract Permeability is one of the most important characteristics of hydrocarbon-bearing formations. Many approaches exist for estimating permeability. Formation permeability is often measured in the laboratory from core samples or evaluated from well test data. However, core analysis and well test data are expensive and available only from a limited number of wells in a field. On the other hand, logging data are available from almost all wells. Therefore, accurate prediction of the formation permeability using logging data becomes very attractive. This paper describes a unique integrated modeling approach to predict formation permeability. By combining digital rock physics (DRP) and downhole logging measurements, formation permeability and capillary pressure were predicted using computational analyses. In this approach, a representative geometrical rock model for the formation at each given depth of interest was numerically generated. These numerical rock models are constrained by the formation parameters derived from NMR and geochemical logging data, i.e., all input parameters for the geometrical rock model such as the rock density, porosity, grain-size distribution, and grain mineralogy, are directly or indirectly obtained from downhole logging measurements. Then, using the geometrical rock model as input, pore size information, capillary-pressure curve, and permeabilities were obtained by computational analyses, including fluid flow simulations based on the lattice-Boltzmann method (LBM). To demonstrate the method's feasibility and applicability, the proposed modelling approach was used on two sets of field data from a North Sea well and an Austin testing well. Permeability and capillary pressure were experimentally determined from laboratory measurements on cores and compared to the simulation results. The predicted permeability values from the proposed DRP approach were in good agreement with measured values from cores. The drainage capillary-pressure curves derived from rock models also matched well with laboratory measurements on core samples. The promising results generated from this study demonstrate the feasibility of a digital core analysis method that integrates a geometrical rock model with downhole logging measurements to accurately and reliably predict formation petrophysical properties in a cost-effective and timely manner.
- North America > United States > Texas (0.69)
- Europe > Netherlands (0.69)
- North America > United States > California (0.68)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.48)
- Geology > Mineral > Silicate > Phyllosilicate (0.48)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock (0.47)
Abstract Development of source-rock resources relies on the rigorous knowledge of their petrophysical properties such as porosity, permeability, and hydrocarbon saturation. In parallel, a concise description of the wettability and pore structures is commended. This paper presents a detailed Nuclear Magnetic Resonance (NMR) T2 study of the wetting characteristics and pore structure in organic-rich source rocks from different locations including the Eagle Ford formation. Although these rocks are highly laminated and calcite dominated, our studies indicated that they have distinct different pore structure and connectivity, and differ in how TOC is dispersed within the rock fabric. We believe that the entailed findings could influence our thinking on how best to produce these shales, wellbore stability, drilling fluid selection and other asset development actions. Source-rock samples with varied amount of total organic content (TOC) were drilled perpendicular or parallel to the laminations. The samples were cut into twin plugs which were sequentially saturated by spontaneous imbibition of 5% KCl brine and diesel (oil). The NMR T2 measurements were used to determine the fluid imbibition rate and amount, as well as the porosity associated with organic and inorganic components of the source rocks. The fracture apertures were obtained via an application of characteristic T2 cutoff times to the NMR T2 distributions. The mineral elements, phases and TOC of the rocks were measured using X-ray Fluorescence (XRF), X-ray Diffraction (XRD) and HAWK pyrolysis, respectively. The prevalence of surface relaxation on the NMR dynamics was prominent as the transverse relaxation took place at time scales (T2 ≤ 100 ms) much shorter than their bulk values. The overall wettability of the samples showed a mixed character as the brine and the oil had been intimately imbibed. Nevertheless, the details of the wetting behavior of the Eagle ford samples and the other samples were different. For instance, Eagle Ford samples imbibed larger volumes of brine and faster than oil, on the contrary the other samples imbibed larger volumes of oil and faster than brine. The apparent preference of oil on the other samples is attributed to their high TOC compared to the Eagle Ford samples. Upon imbibition in these samples, brine is observed to flow along the clay rich bedding planes. In fact, the interaction between brine and clay is identified to be the potential driver of the rock stability problems especially near the wellbore; however it is constrained by the type of residing clays. The discrepancies in the wetting traits are magnified by the presence of fractures which enhanced the network connectivity of both hydrophobic and hydrophilic pores or even across them. Furthermore, the fractures allowed the fluids to surpass the vertical bedding planes and thus accelerating the fluid distribution processes inside the pore space. The fracture apertures were found to range from 1 μm to 15 μm which are typical values for source rocks (Gale et al., 2007, Slatt and O’Brien, 2011).
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.37)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Sabinas - Rio Grande Basin > Eagle Ford Shale Formation (0.99)
- North America > United States > Texas > Maverick Basin > Eagle Ford Shale Formation (0.99)
- (9 more...)
The Impact of Gas Adsorption and Composition on Unconventional Shale Permeability Measurement
Jin, Guodong (Baker Hughes Dhahran Global Technology Center, Saudi Arabia) | Pérez, Héctor González (Baker Hughes Dhahran Global Technology Center, Saudi Arabia) | Agrawal, Gaurav (Baker Hughes Dhahran Global Technology Center, Saudi Arabia) | Khodja, Mohamed R. (King Fahd University of Petroleum and Minerals, Saudi Arabia) | Ali, Abdulwahab Zaki (King Fahd University of Petroleum and Minerals, Saudi Arabia) | Hussaini, Syed Rizwanullah (King Fahd University of Petroleum and Minerals, Saudi Arabia) | Jangda, Zaid Zaffar (King Fahd University of Petroleum and Minerals, Saudi Arabia)
Abstract Permeability determination of organic-rich shales is still a major challenge. Uncertainty in this estimate involves several factors. Two significant ones are the occurrence of gas adsorption which can severely limit gas transport in the pores and understanding the physical chemistry issues of the pore's surface area estimation when using various gases. In this study, we reported our experimental results of permeability measurement on several unconventional shale samples, and investigated the effect of gas type, pore pressure, effective stress and sample orientation on the measured permeabilities. Permeability of shale samples is measured using the complex pressure transient technique. Three different gases, argon, nitrogen, and carbon dioxide, are used as permeating fluid through the samples. Experiments are conducted isothermally at various pore and confining pressures that maintain a constant net effective stress. Generally, samples have higher measured permeabilities when using nitrogen as pore fluid rather than using argon. The discrepancy was attributed to different adsorption potentials between argon and nitrogen: Argon has a similar sorption potential to methane while nitrogen's sorption potential is relatively weak. As expected, the measured permeability of all samples decreases when the pore pressure increases reflecting the reduction in the gas slippage effect. Samples from the same whole core display permeability anisotropy: Horizontal plugs cut parallel to bedding have a higher measured permeability, which is in the range of microdarcy, while the permeability of vertical plugs cut perpendicular to bedding is in the range of nanodarcy. This anisotropy behavior is believed to be caused by the fractures contained within the horizontal samples. The measured permeability is observed to decease with increasing effective stress acting on the samples. This reduction behaves differently: Permeability decreases very slowly when the increasing effective stress is resulted from the decrease of the pore pressure. The enhanced Klinkenberg effect due to the decreasing pore pressure compensates at least partly the permeability reduction resulting from increasing effective stress. However, permeability reduces dramatically when the effective stress increases because of the increasing confining pressure. In this case, the flow channels may be reduced or even closed, thus blocking the flow of gas.
- Asia > Middle East (0.94)
- North America > United States > Texas (0.68)
- Europe (0.68)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (1.00)
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- North America > United States > West Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Virginia > Appalachian Basin > Marcellus Shale Formation (0.99)
- North America > United States > Texas > West Gulf Coast Tertiary Basin > Eagle Ford Shale Formation (0.99)
- (6 more...)