Cave explorers and Geoconservation in the north of England – a changing paradigm?

Recent cave exploration in the Yorkshire Dales glaciokarst of the north of England has mainly been achieved through the removal of sediment infill from passages and entrances. This has resulted in the linking of previously fragmented cave systems to produce the world class Three Counties Cave System. This work has resulted in a growing appreciation by cave explorers of the need to conserve the delicate underground environment. A number of new techniques and approaches have been developed in order to limit the effects of exploratory digging on the cave system along with active efforts to clean up the underground legacy of previous generations of cave explorers. These techniques and approaches pioneered here may have wider applicability to karst areas elsewhere in the world where cave exploration has reached a phase which includes the digging through sediment blockages

STRESS SENSITIVITY OF MERCURY INJECTION MEASUREMENTS

Many petrophysical properties (e.g. permeability, electrical resistivity etc.) of tight rocks are very stress sensitive. However, most mercury injection measurements are made using an instrument that does not apply a confining pressure to the samples. Here we further explore the implications of the use and analysis of data from mercury injection porosimetry or mercury capillary pressure measurements (MICP). Two particular aspects will be discussed. First, the effective stress acting on samples analysed using standard MICP instruments (i.e. Micromeritics Autopore system) is described. Second, results are presented from a new mercury injection porosimeter that is capable of injecting mercury at up to 60,000 psi into 1.5 or 1 in core plugs while keeping a constant net stress up to 15,000 psi. This new instrument allows monitoring of the electrical conductivity across the core during the test so that an accurate threshold pressure can be determined. Although no external confining pressure is applied (unconfined) when using the standard MICP instrument, this doesn’t mean that the measurements can be considered as unstressed. Instead, the sample is under isostatic compression by the mercury until it enters the pore space of the sample. As an approximation, the stress that the mercury places on the sample is equal to its threshold pressure. Thus, the permeability calculated from standard MICP data is equivalent to that measured at its threshold pressure. Not all the samples have the same stress dependency thus comparing measured permeabilities at a single stress with values calculated from standard MICP data, corresponding at different threshold pressures, can lead to erroneous correlations. Therefore, the estimation of permeabilities from standard MICP data can be flawed and uncertain unless the stress effect is included. Results obtained from the new mercury injection system, porosimeter under net stress, are radically different from those obtained from standard MICP instruments such as the Autopore IV. In particular, the measurements at reservoir conditions produce threshold pressures that are three times higher and pore throat sizes that are 1/3rd of those measured by the standard MICP instrument. The results clearly indicate that calculating capillary height functions, sealing capacity, etc. from the standard instrument can lead to large errors that can have significant impact on subsurface characterization

Multi-salinity core flooding study in clay-bearing sandstones, a contribution to geothermal reservoir characterisation

Porosity and permeability measurements aid the characterisation of geothermal reservoirs as they improve understanding of the impact of rock–fluid interactions during the life cycle of wells. Core flooding experiments can help us comprehend the rock–brine electrochemical system as critical parameters like salinity, pH, temperature, or pressure change. If the clay mineral content is significant it can reduce permeability and porosity since these particles can block the pore throat network connectivity through clay migration or swelling. A multi-salinity experiment was conducted in three tight clay-bearing (kaolinite, chlorite, and glauconite) sandstones to study the impact of clay on their petrophysical properties. The experiment consisted of core-flooding brines with salinities of 75 000–200 000 and 0–50 000 ppm NaCl at very low flow rates. Electrical resistivity, the differential pressure across the sample, outlet brine electrical conductivity, and brine permeability were measured. Pore size distribution was acquired by measuring nuclear magnetic resonance (NMR) T2 relaxation time. Cation-exchange capacity (CEC) was derived using the Waxman and Smits (1968) approach. The derived CECs were 71.5, 4.7, and 3.6 meq per 100 g for the kaolinite, chlorite, and glauconite sandstones, respectively. Kaolinite was the least water-sensitive as its permeability decreased uniformly. Chlorite and glauconite were more water-sensitive as in the low salinity range; their permeability increased, and both displayed a bimodal NMR T2 distribution and pore size rearrangement towards the mesoporosity and macroporosity range, indicating that the cation-exchange site prevailed within the pore space. This investigation highlights the importance of ensuring that appropriate fluid chemistry is used on brines flowing in clay-bearing geothermal reservoirs

Permeability of fault rocks in siliciclastic reservoirs: Recent advances

It is common practice to create geologically realistic production simulation models of fault compartmentalized reservoirs. Data on fault rock properties are required, to calculate transmissibility multipliers that are incorporated into these models, to take into account the impact of fault rocks on fluid flow. Industry has generated large databases of fault rock permeability, which are commonly used for this purpose. Much of the permeability data were collected using two inappropriate laboratory practices with measurements being made at low confining pressure with distilled water as the permeant. New fault rock permeability measurements have been made at high confining pressures using formation compatible brines as the permeant. Fault permeability decreases by an average of five fold as net confining pressure is increased from that used in previous measurements (i.e. ∼70 psi) to that approaching in situ conditions (i.e. 5000 psi). On the other hand, permeability increases by around the same amount if reservoir brine is used as the permeant instead of distilled water. So overall, these two inappropriate laboratory practices used in previous studies cancel each other out meaning that legacy fault rock property data may still have value for modelling cross-fault flow in petroleum reservoirs. A poor correlation exists between clay content and fault rock permeability, which is easily explained by the application of a simple clay-sand mixing model. This emphasises the need to gather fault permeability data directly from the reservoir of interest. The cost of such studies could be significantly reduced by screening core samples using a CT scanner so that only samples that are likely to impact fluid flow are analyzed in detail. The stress dependence of fault permeability identified in this study is likely to be primarily caused by damage generated during or following coring. So it is probably not necessary to take into account the impact of stress on fault permeability in simulation models unless the faults of interest are likely to reach failure and reactivate

New Measurements of the Petrophysical Properties of Top and Fault Seals

The paper presents new measurements on key petrophysical properties of fault rocks and shale top seals at subsurface conditions. In particular, results are presented from a new instrument that can make mercury injection capillary pressure measurements at reservoir conditions and accurately measure the threshold pressure. Absolute gas permeability from shale caprock samples measured using an extended pressure transient experiment are presented. New relative permeability measurements are also presented from fault rocks. The stressed MICP measurements suggest that the threshold pressures of fault rocks and top seals could be far higher than has previously been assumed. The transient gas permeability measurements indicate that fractures are often present within shales that may not be present in the subsurface indicating that traditional methods may result in an overestimation of shale permeability. The gas relative permeability behaviour of fault rocks appears to be partially related to their absolute permeability. The oil-water relative permeability behaviour of fault rocks seems highly variable and requires further investigation

Laboratory characterization of the porosity and permeability of gas shales using the crushed shale method: Insights from experiments and numerical modelling

Gas production from shale resource plays has transformed the USA energy market. Despite the knowledge gained from the analysis of large amounts of shale core, appraisal of shale gas resource plays requires a large number of wells to be drilled and tested. Ideally, core analysis results would provide an indication of both the gas filled porosity and permeability of shale resource plays, which could then be used to reduce the number of wells needed during appraisal. A combination of laboratory experiments, numerical modelling and a round-robin test have been conducted to assess the validity of the crushed shale method (CSM), which has been widely used in industry to assess the porosity and permeability of shale. The results suggest that the CSM can provide reasonably precise estimates of porosity measured at ambient stress if a standard sample cleaning method is adopted; although a reliable method to correct these values to subsurface conditions needs to be developed. The CSM does not, however, appear to provide useful information on shale permeability. A round-robin test shows that differences of up to four orders of magnitude in permeability were provided by different laboratories when analysing the same sample. These huge differences seem to occur due to a combination of errors in calculating permeabilities from pressure transients, differences in the way that permeability is calculated as well as uncertainties regarding the effective size of crushed shale particles. However, even if standardized, the CSM may not be particularly useful for characterizing the flow capacity of shale because it is insensitive to the presence of high permeability zones that would control flow in the subsurface