Properties Of Caprock Research Articles

Determining CO2 /brine relative permeability and capillary threshold pressures for reservoir rocks and caprocks: Recommendations for development of standard laboratory protocols

Important parameters for the determination of fluid transport in reservoir rocks are capillary pressures and relative permeabilities for the CO2/brine system. These factors influence the plume migration, residual CO2 trapping and CO2 dissolution in the reservoir brines. CO2-brine relative permeabilities for different rock types are rare in public literature and usually adapted from mathematical relations or from more recent experimental data. The experimental data vary greatly in saturation and relative permeability endpoints, between 10 and 100%. It is necessary to reduce the uncertainty in the data range, since these parameters are sensitive and indispensable for the numerical simulation of the evolution of a CO2 plume in the subsurface. The petrophysical properties of caprocks are the limiting factor to the amount of CO2 stored in potential storage sites. The caprock sealing capacity is determined by the capillary pressure (or column height) at which the trapped fluid starts leaking through a caprock. These rocks have high capillary threshold pressures, which, combined with wettability and interfacial tension (IFT), determine the final column height that a seal can hold. Those three factors - capillary pressure, wettability and IFT - play an important role in the geological storage of CO2 in controlling the potential of CO2 moving through the seal. The capillary threshold pressures need to be determined accurately toestimate brine displacement in caprocks and hence the onset of viscous flow or leakage to the surface. Within the framework of the Carbon Capture Project (CCP3), we plan to establish standard experimental protocols with academic and/or commercial laboratories.

Evaluation of the Petrophysical Properties of a Carbonate-Rich Caprock for CO2-Geological-Storage Purposes

This article, written by Senior Technology Editor Dennis Denney, contains highlights of paper SPE 131525, ’Evaluation of the Petrophysical Properties of a Carbonate-Rich Caprock for CO2- Geological-Storage Purposes,’ by Nicolas Tonnet, and Daniel Broseta, SPE, University of Pau, and Gerard Mouronval, Total, prepared for the 2010 SPE EUROPEC/EAGE Annual Conference and Exhibition, Barcelona, Spain, 14-17 June. The paper has not been peer reviewed. Before any CO2-geological-storage operation, the caprock’s ability to prevent CO2 leakage must be assessed carefully. Preventing leakage is related primarily to the caprock pore structure and to the interfacial properties of the caprock and the fluids in place, specifically the brine that imbibes into the caprock and the CO2 stored in the underlying reservoir. An experimental effort characterized some of these parameters in the carbonate-rich caprock and the reservoir conditions of a depleted gas field in France. Introduction The ability of the caprock to prevent leakage in a CO2-geological-storage operation must be assessed early in the planning stage in a depleted hydrocarbon reservoir or a deep saline aquifer. In the case of hydrocarbon reservoirs, the existence of a top seal (or caprock) is proven, but only with respect to hydrocarbons. In the case of deep saline aquifers, little is known about the confining properties of the overlying low-permeability layers, referred to here as caprock for simplicity. Leakage through the caprock may occur by either mechanical or capillary failure. Both processes are caused by an overpressure in the fluid saturating the underlying reservoir. Capillary failure is considered the normal mode of caprock failure under moderate-overpressure conditions, whereas mechanical failure tends to occur for high overpressures and very tight caprocks. Mechanical failure, which includes the hydraulic or thermal generation of fractures and the reactivation of pre-existing faults, may give rise to significant leakage rates in specific zones of the subsurface. Capillary failure, however, gives rise to more pervasive and slower leakage. It occurs when pressure in the CO2 phase in the reservoir is large enough to force the CO2 into the overlying fine-grained (or low-permeability) caprock, in which the saturating brine phase is thus displaced by the intruding CO2 phase. This drainage process is controlled by the caprock pore structure and by the interfacial properties of the caprock and saturating fluids (brine and CO2). To avoid leakage, the reservoir pressure beneath the caprock should be maintained below displacement (breakthrough) pressure, Pd, assumed here to be lower than the minimum pressure required for caprock mechanical failure. However, if the pressure is higher than Pd (but still lower than the pressure for caprock mechanical failure), leakage through the caprock is acceptable if gas (CO2) effective permeability is low enough. Effective permeabilities in the nanodarcy range or lower are considered acceptable.

Two-Phase Cement/CO2/Brine Interaction in Wellbore Environments

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 126666, ’Computational Studies of Two-Phase Cement-CO2-Brine Interaction in Wellbore Environments,’ by J.W. Carey and P.C. Lichtner, Los Alamos National Laboratory, originally prepared for the 2009 SPE International Conference on CO2 Capture, Storage, and Utilization, San Diego, California, 2-4 November. Wellbore integrity is essential to ensuring long-term isolation of buoyant supercritical carbon dioxide (CO2) during geologic sequestration. The full-length paper summarizes recent progress in numerical simulations of cement/CO2/brine interactions with respect to migration of CO2 outside of casing. Using typical values for the hydrologic properties of cement, caprock (shale), and reservoir materials, the study shows that the capillary properties of good-quality cement will prevent flow of CO2 into and through cement. Introduction Wellbore integrity signifies isolation of fluids in the subsurface. In the geologic sequestration of CO2, this requires preventing the migration of buoyant, supercritical CO2, a fluid that is highly mobile (with a viscosity approximately 1/10 that of water) and that is partially immiscible with brine and oil. Aqueous CO2 forms by reaction of supercritical CO2 and brine and generates an acidic solution (pH in the range of 4.5 to 5 in the presence of calcite) that is chemically reactive with the Portland cement and steel casing that provide isolation in most wellbore systems. Wellbore failure in the context of geologic sequestration is leakage that occurs either through primary defects (e.g., along a microannulus at the cement/casing interface) or through secondary defects induced by chemical degradation of the wellbore system. One of the key goals in the evaluation of the long-term safety and security of CO2 sequestration is thus the determination of whether zonal isolation deteriorates or improves through chemical interactions with CO2, in addition to calculation of the flux of CO2 as a function of conditions in the wellbore environment. Chemical reaction of CO2 with Portland cement is complex and involves dissolution of portlandite, dis-solution of calcium silicate hydrate (the primary structural material in cement), and the precipitation of calcium carbonate (CaCO3). If the first two reactions predominate, the flux of CO2 will increase with time as the cement sheath deteriorates. On the other hand, if precipitation of CaCO3 is significant, CO2-leakage pathways may self-seal and ultimately limit the flux of CO2. The simulations were motivated by observations of cement performance at the CO2-enhanced-oil-recovery SACROC Unit in west Texas and by recent results from a natural CO2 reservoir. The SACROC well was 55 years old with 30 years of operation as a CO2 producer and injector. Samples of cement from 3 m above the reservoir/caprock interface showed reactions with CO2 at both the casing and formation interfaces. Preliminary 1D diffusion-based models were able to reproduce the observed mineralogical changes at SACROC. In particular, the model reproduced the complete carbonation of the cement along a 0.5-cm reaction front adjacent to the caprock and the presence of a siliceous deposit at the interface between the carbonated and uncarbonated cement.

Long-term well bore integrity in Otway: Integrating ultrasonic logs, cement petrophysics, and mechanical analysis

The CO2CRC pilot project in the Otway basin of Australia has recently started injecting supercritical CO2 into a depleted gas reservoir, in what is the first geological storage project in the southern hemisphere. For CO2 geological storage to be successful, every effort should be made to ensure that CO2 doesn’t find its way back to the atmosphere for a very long time - possibly centuries. Potable aquifers and other permeable formations (e.g. hydrocarbon deposits) must also be protected against CO2 contamination. Wells are generally recognized as a weak spot in CO2 storage, where containment can break down. This is because cement, steel and elastomers can be corroded by CO2, and the ageing process will be accelerated by any defects in the cement sheath. In particular, containment must be assured across impermeable geologic barriers - the caprock. In Otway’s case, an objective of the project was to contain CO2 below a relatively short shale interval (around 150 ft in length). This represents the primary barrier, backed up by a much longer section higher up the well. This paper discusses how the integration of 3D ultrasonic imaging together with an advanced understanding of cement petrophysical properties brings about a detailed picture of the cement sheath. Caprock properties and borehole detailed shape and features can also be characterized through formation evaluation logging. The actual in-situ cement properties can then be used in a mechanical analysis of the cement-rock-casing system in order to assess the occurrence of cement defects (such as cracks and microannuli). This methodology is applied step-by-step over the short section of cement that must assure isolation across the primary barrier, providing an accurate input to long-term leak models that will estimate the risk to containment over hundreds of years.

The effectiveness assessment of gas accumulation processes in Kuqa depression, Tarim Basin, Northwest China

The effectiveness of gas accumulation processes is controlled by several main geological factors including charging force, features of gas conduit, sealing properties of caprock, etc. Based on the analysis and statistics of the large-medium size gas accumulations in China, the main parameters, including the excess pressure difference between the source rock and reservoir bed, the area coefficient of the gas conduit, and the thickness or displacement pressure of caprock, and the criteria for the assessment of gas accumulation processes have been established. Using the parameters and the criteria above, the effectiveness of gas accumulation processes in the Kuqa depression was quantitatively evaluated. By integrating the parameters of the excess pressure difference between the source rock and reservoir bed, the area coefficient of fault conduit system, and the caprock thickness in gas charging period, a comprehensive assessment of the effectiveness of gas accumulation in the Kuqa depression has been made. The result reveals that the Tubei-Dawan area, the Central Kelasu area and the Dongqiu-Dina area are three highly-effective areas for gas accumulation in the Kuqa depression.

Seismic reservoir prediction using Bayesian integration of rock physics and Markov random fields: A North Sea example

Quantitative interpretation of seismic data for reservoir rock and fluid properties commonly relies on deterministic rock physics relations and may often neglect statistical variability or spatial correlation. Geostatistical methods, on the other hand, take into account spatial dependence but results are often obtained without properly formalizing rock physics relations between seismic measurements and rock and fluid properties. This paper presents a strategy for integrating deterministic rock physics relations and spatial, statistical representations within a Bayesian framework. Data from the turbidite Glitne Field in the North Sea (Figure 1) provide an example for the approach. Because the reservoir is very heterogeneous, merging statistics with rock physics is particularly worthwhile to improve seismic reservoir prediction. Figure 1. The location of Glitne Field in the North Sea and the top Heimdal horizon as illustrated by reflection times. Available data are AVO seismic attributes, well observations, two-way seismic traveltimes, and cap-rock properties. The focus is on describing the spatial probability distribution of reservoir facies and fluid saturation along the seismic horizon representing the top Heimdal Formation (Figure 1), which is capped by Lista Formation at approximately 2000 m. Available data include AVO attributes (zero-offset reflectivity and AVO gradient) extracted from 3-D prestack seismic data and log-based analysis of facies and fluid saturation in four wells. Figure 2 shows zero-offset reflectivity (top, left) and AVO gradient (bottom, left) along the horizon (with the facies and fluid observations in the four wells indicated), a plot of zero-offset reflectivity versus AVO gradient (top, right), and a well log from the area (bottom, right). Two-way seismic traveltimes to the horizon of interest and cap-rock properties (density, P - and S -wave velocity) from well logs are also available (Figure 1). A 245 × 505 grid, each block being 12.5 × 12.5 m2, covers the domain of interest. This …

Depressurization of hydrocarbon-bearing reservoirs in exhumed basin settings: evidence from Atlantic margin and borderland basins

Abstract Depressurization of reservoirs in petroliferous basins commonly occurs through cap-rocks at structural crests where pore pressures are locally elevated because of either the presence of a hydrocarbon column or the redistribution of overpressures by water flow along laterally extensive inclined permeable aquifers. In exhumed petroliferous basins this deflation of excess pore pressures is enhanced by the denudation process, which results in the large-scale removal of overburden during regional uplift. Evidence from the exhumed basins of the Atlantic margin indicates that hydrocarbon accumulations in these basins are commonly characterized by underfilled traps and hydrostatically pressured or modestly overpressured reservoirs. These observations are reviewed in the context of the generic mechanisms by which top-seals leak, the properties of cap-rocks and the physical processes that occur during exhumation. Water-wet shaly cap-rocks can form a capillary seal to a hydrocarbon column while simultaneously accommodating brine flow and equilibration of pressures between the reservoir and the top-seal. In contrast, thick, low-permeability shale or evaporite sequences may form pressure seals that restrict vertical brine and hydrocarbon flow and prevent the equilibration of aquifer pressures above and below the seal. In any sedimentary basin, the presence of regional pressure seals can result in a layered hydrogeological regime with hydrostatically pressured strata decoupled from over- or underpressured cells. Recently exhumed basins typically show limited overpressuring and in a number of these basins underpressured reservoirs have been described. Post-exhumation overpressure generation is primarily driven by tectonic compression, aquathermal pressuring and hydraulic head. The fluid retention capacity of any cap-rock lithology during exhumation is dependent upon the physical and mechanical characteristics of the cap-rock at the time of exhumation and the timing and conditions of the associated deformation relative to the timing of hydrocarbon emplacement. The permeability and deformational characteristics of halite render it an excellent cap-rock with a high retention capacity, even under conditions of exhumation. However, mudrocks may also form effective cap-rocks in exhumed basins when the deformation associated with exhumation occurs before embrittlement and the shale cap-rock exhibits ductile behaviour. Shale and evaporite cap-rocks form the main regional seals to hydrocarbon accumulations in exhumed basins of the Atlantic margin and borderlands. Syn-exhumation top-seal efficiency (fluid retention capacity) is a major exploration risk in these basins, although post-exhumation top-seal integrity in these basins may be relatively high under certain conditions. Consequently, a major exploration risk factor in exhumed basin settings pertains to the limited hydrocarbon budget available post-regional uplift and the efficiency of the remigration process.

Geophysical properties of cap rocks in Qiongdongnan Basin, South China Sea

Based on measured petrophysical properties and statistical methods, relationship between petrophysical properties and well log and seismic parameters are established empirically to evaluate the quality of cap rocks in Qiongdongnan Basin. Good cap rocks show high density and low sonic travel time. Four zones can be divided vertically according to displacement pressures in Qiongdongnan Basin, best seal quality is found in the depth range of 2000–4000 m. The Ya 13-1 structure has excellent cap rock, which contributes to its abundant gas accumulation.

A fluid dynamic classification of hydrocarbon entrapment

Fluid dynamic potentials are critical to the entrapment, distribution, phase, leakage and migration of hydrocarbons. The classification system combines two cap rock properties (static and dynamic) with five seal and leakage modes (capillary seal, pressure seal, hydraulic resistance seal, water drive leakage and hydraulic fracturing leakage) and two hydrocarbon migration mechanisms into and out of a trap (fill/spill and fill/leak). Static cap rocks, such as thick shales, usually seal more than the vertical closure of the trap, as a consequence of the critical pore throat capillary pressure (capillary seal). In two-phase hydrocarbon systems fill/spill tends to concentrate gas. Hydraulic fracturing is usually required to generate significant leakage through static cap rocks. Then fill/leak tends to concentrate oil. Dynamic cap rocks, such as inhomogeneous sand/shale sequences and faults have less sealing capacity than the static cap rocks, but are more widespread. They are strongly affected by variations in the fluid dynamic properties and are less dependent on capillary pressure. Water potentials are often critical, for seal (pressure seal) or for leakage and redistribution (water drive leakage). Hydraulic resistance seal is important for trapping of oil and crucial for concentration of oil relative to gas (fill/leak).

Comparative Study of the Sealing Properties of Cap Rocks from Northern Germany and Haltenbanken Area, Norway: ABSTRACT

A comprehensive study was conducted to determine the sealing properties of 12 Permian and Upper Carboniferous cap rock samples from N. German gas reservoirs and 15 Jurassic shales from the Haltenbanken area offshore Norway. The samples were characterised by standard mineralogical (XRD, SEM optical microscopy) and geochemical (XRF, TC, TOC, Rock-Eval) methods. Samples from the N. German Permian basin were red beds with essentially no organic matter (OM) comprising shales, siltstones and brecciae. The shale cap rocks from Haltenbanken had TOC contents between 0.8 and 5.5 %. Permeability measurements with fresh water yielded values ranging from below the detection limit of < 0.1 nanodarcy (10{sup -22} m{sup 2}) up to 100 nanodarcy for the red shales and siltstones. The brecciae which are envisaged as regional lateral seals had permeabilities around 1300 nanodarcy. Permeabilities of the Jurassic shales from Norway ranged between 2 and 400 nanodarcy. Diffusion experiments were carried out on the water-saturated cap rocks with methane at 150{degrees}C. For the OM-containing shales from Haltenbanken diffusion coefficients ranged from 1.4 - 11.4 x 10{sup -11} m{sup 2}/s whereas the values for the red bed samples from N. Germany were generally higher (10 - 45 x 10{sup -11} m{sup 2}/s). Themore » effect of OM on the diffusion coefficient is attributed to sorption/desorption processes. Mercury porosimetry yielded displacement pressures between 16 and 800 bar for the Haltenbanken samples corresponding to equivalent pore radii of 400 - 10 nm. For the N. German shale cap rocks displacement pressures were usually higher and the pore radius distributions showed most prominent pore radii close to or below the experimental limit of 2.1 nm.« less

Numerical Simulations of How Cap-Rock Properties Can Control Differential Entrapment of Oil

Numerical Simulations of How Cap-Rock Properties Can Control Differential Entrapment of Oil

On the Significance of Cap Rock Properties to the Formation of Natural Gas Accumulations

On the Significance of Cap Rock Properties to the Formation of Natural Gas Accumulations