Hydrocarbon production, gas recovery from shale, CO2 storage and water management have a common scientific underpinning: multiphase flow in porous media. This book provides a fundamental description of multiphase flow through porous rock, with emphasis on the understanding of displacement processes at the pore, or micron, scale. Fundamental equations and principal concepts using energy, momentum, and mass balance are developed, and the latest developments in high-resolution three-dimensional imaging and associated modelling are explored. The treatment is pedagogical, developing sound physical principles to predict flow and recovery through complex rock structures, while providing a review of the recent literature. This systematic approach makes it an excellent reference for those who are new to the field. Inspired by recent research, and based on courses taught to thousands of students and professionals from around the world, it provides the scientific background necessary for a quantitative assessment of multiphase subsurface flow processes, and is ideal for hydrology and environmental engineering students, as well as professionals in the hydrocarbon, water and carbon storage industries.

Multiphase Flow in Permeable Media: A Pore-Scale Perspective

In many tight-gas basins of the western United States distinguishing between productive and non-productive low-permeability sandstones, and predicting relative amounts of gas and water production is difficult. Comparison of gas shows, calculated water saturations, and saturation-height profiles between gas-productive and non-productive sandstones of equal reservoir quality all appear similar. Capillary pressure derived height functions are difficult to apply, and classic rock-typing procedures lack the predictive capability that is common to more traditional reservoirs. Basin reconstructions suggest the timing of petroleum charge and migration preceded maximum burial and uplift. This initial charge was likely a primary drainage displacement with reservoir porosity greater by a factor of 2-3 relative to values found today and permeability greater by 1-3 orders of magnitude. These reservoir systems became low-permeability following initial charge reflecting continued diagenesis throughout burial, subsequent uplift and erosion. With burial, decreasing pore volume caused water saturations and gas columns to increase. During uplift and erosion gas columns adjusted to changing structural configuration. In some cases this led to gas accumulations being leaked and spilled. In other cases, structural readjustment resulted in capillary imbibition and, in some cases, secondary (or higher order) drainage and imbibition. Within trapped accumulations, gas expansion upon uplift further increased gas columns. In cases where gas columns were spilled or within migration pathways imbibition led to residual or near-residual water saturations. Conventional formation evaluation is fundamentally rooted in concepts associated with primary drainage displacement. Tight-gas reservoirs that have experienced late uplift following an earlier phase of charge are unlikely to be characterized by primary drainage and are much more likely to be characterized by imbibition or secondary (or higher order) drainage and possibly imbibition. The hysteresis between primary drainage and imbibition or secondary (or higher order) drainage and imbibition in tight-gas reservoirs is significant and unlike many more traditional reservoirs does not tend to converge on a narrow range of values. Estimates of water saturation are scalar values and do not contain information that allows the saturation history and displacement direction to be deciphered. Recognition that reservoirs are unlikely to be in primary drainage equilibrium is a fundamental paradigm shift that impacts petroleum evaluation at all scales ranging from basin potential to completion decisions within a given well. Although this paper is written from the perspective of tight-gas petroleum systems, the principles are equally applicable to low-permeability oil reservoirs.

The evolution of pore-scale fluid-saturation in low-permeability sandstone reservoirs

Abstract Carbonate rock typing provides a vehicle to propagate petrophysical properties through association with geological attributes and, therefore, is critical for distributing reservoir properties, such as permeability and water saturation, in the reservoir model. The conventional approaches to rock typing have significant gaps in incorporating diagenetic processes, transferring rock types from core to log domain, accounting for fractures and using appropriate methodology to realistically distribute rock types in the static reservoir model. The workflow proposed in this paper addresses these issues in a comprehensive way by determination of petrophysical rock types (PRTs), which control static properties and dynamic behaviour of the reservoir, while optimally linking to geological attributes (depositional and diagenetic) and their spatial interrelationships and trends. This approach is novel for the fact that it: (1) integrates geological processes, petrophysics and Earth modelling aspects of rock typing; (2) integrates core and log scales; and (3) provides a flexible ‘road map’ from core to 3D model for variable data scenarios that can be updated with progressive changes in data quality and quantity during the life cycle of an asset. This paper introduces the rationale behind this workflow, and demonstrates its workings and agility through deployment in two large carbonate fields.

Carbonate Petrophysical Rock Typing - Integrating Geological Attributes and Petrophysical Properties While Linking With Dynamic Behavior

Carbonate petrophysical rock typing: integrating geological attributes and petrophysical properties while linking with dynamic behaviour

Pore-scale X-ray imaging with measurement of relative permeability, capillary pressure and oil recovery in a mixed-wet micro-porous carbonate reservoir rock

Variations in Bounding and Scanning Relative Permeability Curves With Different Carbonate Rock Type

Experimental measurements of capillary pressure, resistivity index and relative permeability display hysteresis manifested through the dependence of these properties on the saturation path and saturation history whenever fluid saturations undergo cyclic processes. At the pore scale, hysteresis is typically influenced by contact-angle hysteresis, trapping of one phase by another and wettability changes. A laboratory study was conducted to investigate hysteresis effects measured on reservoir core plugs for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering reservoir rock types (RRT) were selected based on whole-core and plug X-ray CT, high-pressure mercury injection, porosity, permeability and thin-section analyses. Primary drainage and imbibition capillary pressure and resistivity index (PcRI) were measured by the porous-plate method using stock tank oil and simulated formation brine at reservoir temperature and overburden conditions. Large hysteresis effects were obtained between primary drainage and imbibition for both Pc and RI curves. Low residual oil saturations (Sor) were measured at the end of forced imbibition indicating oil-wet to mixed-wet characteristics. Nonlinear RI curves were found during imbibition which could not be described by conventional Archie equation. Water-oil relative permeability curves were measured on similar reservoir core samples by the steady-state technique using live fluids at full reservoir conditions with in-situ saturation monitoring. Hysteresis effects on both oil and water curves were observed between primary drainage and imbibition, and appear to be influenced by the sample rock type involved (i.e. wettability and pore structure). The strong hysteresis in RI was explained by a fluid invasion behavior at the pore level, and was attributed to varying displacement mechanisms between primary drainage and imbibition. Conventional assumption of Archie behavior is therefore not always valid for such carbonate rock types. This RI hysteresis, together with the variation of Kr hysteresis trends with different rock types, may help improve the current hysteresis models and provide better understanding of the hysteresis phenomena in natural porous media.

/pdf/hysteresis-of-capillary-pressure-resistivity-index-and-31vl71w2qq.pdf

Hysteresis of Capillary Pressure, Resistivity Index and Relative Permeability in Different Carbonate Rock Types

Gas Process Displacement Efficiency Comparisons on a Carbonate Reservoir

Relative permeability curves generally exhibit hysteresis between different saturation cycles. This hysteresis is mainly caused by wettability changes and fluid trapping. Different rock types may experience different hysteresis trends because of variations in pore geometry. Relative permeability curves may also be a function of the saturation height in the reservoir. A detailed laboratory study was performed to investigate relative permeability behavior for a major carbonate hydrocarbon reservoir in the Middle East. Representative core samples covering five reservoir rock types (RRTs) were identified on the basis of whole core and plug X-ray computed tomography (CT), nuclear magnetic resonance (NMR) T2, mercury injection capillary pressure (MICP), porosity, permeability, and thin-section analyses. Primary-drainage (PD) and imbibition water/oil relative permeability (bounding) curves were measured on all the five rock types by the steady-state (SS) technique by use of live fluids at full reservoir conditions with in-situ saturation monitoring (ISSM). Imbibition relative permeability experiments were also conducted on the main RRT samples to assess the relative permeability (scanning) curves in the transition zone (TZ) by varying connate-water saturations. Hysteresis effects were observed between PD and imbibition cycles, and appeared to be influenced by the sample rock type involved (i.e., wettability and pore geometry). Variations in relative permeability within similar and different rock types were described and understood from local heterogeneities present in each individual sample. This was possible from dual-energy (DE) CT scanning and high-resolution imaging. Different imbibition trends from both oil and water phases were detected from the scanning curves that were explained by different pore-level fluidflow scenarios. Relative permeability scanning curves to both oil and water phases increased with higher connate-water saturation. Relative permeability to oil was explained on the basis of the occupancy of the oil phase at varying connate-water saturations. The change in the water relative permeability trend was addressed on the basis of the connectivity of water at the varying connatewater saturations. These results and interpretations introduced an improved understanding of the hysteresis phenomena and fluidflow behavior in the TZ of a Cretaceous carbonate reservoir that can assist in the overall reservoir modeling and well planning.

https://www.ux.uis.no/~s-skj/Spe-papers/SPE-162265-PA-P.pdf

Variations in Bounding and Scanning Relative Permeability Curves with Different Carbonate Rock Types

Reservoir heterogeneity is dependent upon depositional environments and subsequent events in the history of the reservoir. From a previous work, we reported variations in poroperms and cementation factor “m” as a function of different scale measurements and emphasized the importance of whole cores in better capturing reservoir heterogeneity. In the present work, we have extended our investigation on the effect of the multi-scale measurements on hundreds of samples from four different wells in a giant carbonate field in Abu Dhabi. Laboratory measurements were conducted on four different scale samples, ranging from full diameter 4 inch whole cores down to 1 inch plug samples. The smaller size samples were taken from the same bigger volume samples for direct comparisons. The multi-scale effect was studied on the variations of reservoir properties including porosity, permeability, capillary pressure and saturation exponent “n”. The multi-scale analyses confirmed the variations in rock properties and the influence of heterogeneity on reservoir performance. Whole core porosities tend to be lower than plug porosities. Permeability variations between different sample sizes appear to be governed by the degree of heterogeneity. Different capillary pressure and “n” curves were obtained from whole core and plug samples. The changes in rock properties as a function of sample scale (size) improve the understanding of reservoir heterogeneity and minimize the uncertainty in STOOIP calculations. INTRODUCTION Serag and co-workers [1] investigated the effect of multi scale measurements (whole cores down to small trims) on poroperm and cementation factor “m”. The samples came from single well “E” in the field, and the trims were taken from the plugs but the plug samples were cut adjacent to the whole cores. The main findings were that whole core porosity matched very well log data, and the plug porosities as compared to the whole core data were systematically higher. We found out that the degree of heterogeneity played a major role in comparing whole core to plug permeability. “m” was systematically reported lower in the measured whole core samples. The investigation has been extended to include hundreds of samples taken from 4 different wells in the same field. Laboratory measurements were conducted on full diameter four inch whole cores down to one inch diameter core plug samples. The smaller samples were taken from the same bigger volume samples for direct comparisons. The multi-scale effect was studied

Mohammed Zubair Kalam

Papers

Variations in Bounding and Scanning Relative Permeability Curves With Different Carbonate Rock Type

Hysteresis of Capillary Pressure, Resistivity Index and Relative Permeability in Different Carbonate Rock Types

Gas Process Displacement Efficiency Comparisons on a Carbonate Reservoir

Variations in Bounding and Scanning Relative Permeability Curves with Different Carbonate Rock Types

The Impact of Heterogeneity and Multi-Scale Measurements on Reservoir Characterization and STOOIP Estimations