Low Permeability Sedimentary Rocks Research Articles

A novel method to estimate the Stress-Dependent Kozeny-Carman constant of Low-Permeability, clastic sedimentary rocks

The stress-dependent permeability of low-permeability sedimentary rocks has seized attention because of the growing need for fossil fuels, geological carbon sequestration, and radioactive waste disposal. The Kozeny-Carman equation (K-C equation) is a well-known model for predicting the permeability of sedimentary rocks. The Kozeny-Carman constant (K-C constant, ckc) in the K-C equation accounts for the shape of the pores and the complexity of the pore conduit geometry in rocks. The pore structure of rocks varies owing to compaction at different burial depths. Therefore, the ckc is stress-dependent, a key parameter for understanding the stress-dependent permeability of rocks. However, measuring the stress-dependent ckc in low-permeability rocks is challenging. The present study proposes a novel approach for measuring the stress-dependent ckc of low-permeability rocks. The key elements of the proposed approach are (1) utilizing the Klinkenberg slip factor to evaluate the pore structure of rocks under stress, and (2) measuring rock porosity and permeability simultaneously under stress. This study amended the existing apparatus to fulfill the aforementioned purpose. Silty sandstone and clayey siltstone were selected to illustrate the novel ckc measurement method. The measured ckc values were compatible with the measurement results of documented sandstones and mudstones (most stress-independent). Interestingly, the ckc increased with increasing effective confining stress but started to decrease when the applied stress exceeded a certain critical value. Finally, we provide a synthetic case demonstrating the importance of considering stress-dependent ckc for permeability prediction under stress. If we neglect the stress dependence of ckc, the prediction of permeability using the K-C equation can induce errors up to several orders of magnitude.

Gas relative permeability evaluation in tight rocks using rate-transient analysis (RTA) techniques

The evaluation of effective and relative gas permeability is critical for modeling hydrocarbon recovery from low-permeability (unconventional) reservoirs, and for evaluating the potential for clean energy pathways such as carbon capture and sequestration and hydrogen storage in subsurface. Nevertheless, due to the low flow rates and long experimental times associated with low-permeability (nanodarcy/microdarcy range) sample testing, measuring relative permeability through conventional techniques is technically challenging, time-consuming, and expensive. Additionally, and importantly, none of the routine laboratory techniques for measuring relative permeability can mimic the boundary conditions under which wells are produced from, or injected into, in the field.For the first time, effective and relative gas permeability of partially-saturated low-permeability sedimentary rocks were investigated using state-of-the-art core analysis techniques based on rate-transient analysis (RTA). Conventional and new straight-line analysis methods, commonly applied to production data in the field, were used to estimate effective gas permeability of core plugs under variable stress conditions and water saturations. Five low-permeability siltstone and organic/clay-rich samples, differing in mineralogy, porosity, and pore size distribution, were analyzed for proof-of-concept testing.The observed flow regimes consist of transient linear flow followed by boundary-dominated flow regimes, as previously reported for field data. Satisfactory correlation (average coefficient of variation less than 7%) between permeability estimates using different RTA techniques demonstrates the applicability of this method for effective and relative permeability assessment of partially-saturated ultra-tight reservoirs (down to less than 1.0∙10−5 md). Importantly, test times after the initiation of the production phase, were on the order of minutes, which is significantly shorter than those commonly achievable using conventional techniques (e.g., hours using pulse-decay gas permeability testing). Effective gas permeability (from 1.5∙10−3 to 7.5∙10−6 md), and slip factor (from 715 to −286 psia−1), decreased with increasing water saturation (0–53%), reflecting the lower contribution of slip flow to gas transport. Effective gas permeability decreased with increasing effective stress (500–4000 psia), likely due to reduced effective (transport) pore throat size and increased tortuosity. The reduction of slip factor and the observed stress dependency with water saturation is attributed to the channel flow mechanism.

Effect of the pore water composition on the diffusive anion transport in argillaceous, low permeability sedimentary rocks

The effect of the pore water composition on the diffusive anion transport was studied for two different argillaceous, low permeability sedimentary rocks, Opalinus Clay (OPA) and Helvetic Marl (HM). The samples were saturated with different solutions with varying molar concentration and different main cations in the solution: NaCl based pore solutions and CaCl2 based pore solutions. The total porosity was measured by through-diffusion experiments with the neutral tracer HTO. Experiments performed in NaCl solutions resulted in a porosity of 0.12 for OPA and 0.03 for HM, and are consistent with results of the experiments in CaCl2 solutions. The total porosity was independent of the molar concentration, in contrast to the measured anion porosity, which increased with increasing molar concentration. It could further be observed that the pore solution based on the bivalent cation calcium shielded the negative surface charge stronger than the monovalent cation sodium, resulting in a larger measureable anion-accessible porosity in the case of CaCl2 solutions.The data was modelled based on an adapted Donnan approach of Birgersson and Karnland (2009). The model had to be adjusted with a permanent free, uncharged porosity, as well as with structural information on the permanent anion exclusion because of so-called bottleneck pores. Both parameters can only be evaluated from experiments. Nevertheless, taking these two adaptions into account, the effect of varying pore water compositions on the anion-accessible porosity of the investigated argillaceous rocks could be satisfactorily described.

A comparative anion diffusion study on different argillaceous, low permeability sedimentary rocks with various pore waters

Through-diffusion experiments with tritiated water (HTO) and 36Cl− as a function of pore water concentration (0.01–5 M) were performed on two Ordovician-age argillaceous rock samples from the Blue Mountain Fm and Queenston Fm shales of the Paleozoic intracratonic Michigan Basin in Canada. This study reveals that the effect of ionic strength on the anion-transport porosity is similar, and only the minimal anion excluded porosity is higher in the Blue Mountain Fm shale. The differences in rock sample mineralogy cannot explain this effect. It is hypothesized that the structure of the Blue Mountain Fm shale samples has led to pore space openings sufficiently small that they behave as interlayers. Such pores are defined as interlayer equivalent (ILE) pores. These ILE pores, as in the case of interlayer pores, can act to permanently limit the anion-accessible porosity. Pore-size distribution measurements provide further evidence of increased potential for ILE pores within the Blue Mountain Fm samples. A Donnan model, which includes consideration of both ILE and uncharged pores, is shown to describe the effect of molar concentration on the anion-accessible porosity in the argillaceous rocks investigated.

Mechanical stratigraphic controls on natural fracture spacing and penetration

Fine-grained low permeability sedimentary rocks, such as shale and mudrock, have drawn attention as unconventional hydrocarbon reservoirs. Fracturing – both natural and induced – is extremely important for increasing permeability in otherwise low-permeability rock. We analyze natural extension fracture networks within a complete measured outcrop section of the Ernst Member of the Boquillas Formation in Big Bend National Park, west Texas. Results of bed-center, dip-parallel scanline surveys demonstrate nearly identical fracture strikes and slight variation in dip between mudrock, chalk, and limestone beds. Fracture spacing tends to increase proportional to bed thickness in limestone and chalk beds; however, dramatic differences in fracture spacing are observed in mudrock. A direct relationship is observed between fracture spacing/thickness ratio and rock competence. Vertical fracture penetrations measured from the middle of chalk and limestone beds generally extend to and often beyond bed boundaries into the vertically adjacent mudrock beds. In contrast, fractures in the mudrock beds rarely penetrate beyond the bed boundaries into the adjacent carbonate beds. Consequently, natural bed-perpendicular fracture connectivity through the mechanically layered sequence generally is poor. Fracture connectivity strongly influences permeability architecture, and fracture prediction should consider thin bed-scale control on fracture heights and the strong lithologic control on fracture spacing.

Effect of confining pressure on diffusion coefficients in clay-rich, low-permeability sedimentary rocks

The effect of confining pressure (CP) on the diffusion of tritiated-water (HTO) and iodide (I−) tracers through Ordovician rocks from the Michigan Basin, southwestern Ontario, Canada, and Opalinus Clay from Schlattingen, Switzerland was investigated in laboratory experiments. Four samples representing different formations and lithologies in the Michigan Basin were studied: Queenston Formation shale, Georgian Bay Formation shale, Cobourg Formation limestone and Cobourg Formation argillaceous limestone. Estimated in situ vertical stresses at the depths from which the samples were retrieved range from 12.0 to 17.4MPa (Michigan Basin) and from 21 to 23MPa (Opalinus Clay). Effective diffusion coefficients (De) were determined in through-diffusion experiments. With HTO tracer, applying CP resulted in decreases in De of 12.5% for the Queenston Formation shale (CPmax=12MPa), 30% for the Georgian Bay Formation shale (15MPa), 34% for the Cobourg Formation limestone (17.4MPa), 31% for the Cobourg Formation argillaceous limestone (17.4MPa) and 43–46% for the Opalinus Clay (15MPa). Decreases in De were larger for the I− tracer: 13.8% for the Queenston shale, 42% for the Georgian Bay shale, 50% for the Cobourg Formation limestone, 55% for the Cobourg Formation argillaceous limestone and 63–68% for the Opalinus Clay. The tracer-specific nature of the response is attributed to an increasing influence of anion exclusion as the pore size decreases at higher CP.Results from the shales (including Opalinus Clay) indicate that the pressure effect on De can be represented by a linear relationship between De and ln(CP), which provides valuable predictive capability. The nonlinearity results in a relatively small change in De at high CP, suggesting that it is not necessary to apply the exact in situ pressure conditions in order to obtain a good estimate of the in situ diffusion coefficient. Most importantly, the CP effect on shale is reversible (±12%) suggesting that, for argillaceous rocks, it is possible to obtain De values that are representative of the in-situ condition by conducting measurements on re-pressurized samples that were obtained with standard drilling practices. This may not be the case for brittle rock samples as the results from limestone suggest that irreversible damage occurred during the pressure cycling.

Modeling of impact of hydraulic fractures on the process of fluid displacement from low-permeability sedimentary rocks

Mathematical modeling of fluid displacement from low­permeability (shale) sedimentary rocks in the pattern waterflooding elements considering the impact of hydraulic fractures is performed. Based on numerical methods of comprehensive analysis (quasiconformal mappings), numerical algorithms for the calculation of filtration characteristics: saturation field, velocity quasipotential, time of the displacing fluid breakthrough to the production well and its complete waterflooding are developed. The algorithm also allows determining the coordinates of the critical “suspension” points and their quasipotential values, fluid interface position at different time points, the overall filtration rate of the production well, the dependence of oil fraction in it. For an effective analysis of the research, calculations of the volume of the displaced fluid in the reservoir within a certain time and the volume of the remaining fluid in the reservoir at an arbitrary time are performed. This allowed predicting the rate of waterflooding of production wells and identifying the features of operation under the projected arrangement of wells and hydraulic fractures on them. It was found that the “transverse direction” (with respect to injection wells) of hydraulic fractures accelerates the time of the displacing reagent breakthrough to the production well (although provides some growth of oil withdrawal values at the initial stages), and their “longitudinal” direction reduces the number of oil stagnation zones.

The relationships among brittleness, deformation behavior, and transport properties in mudstones: An example from the Horonobe Underground Research Laboratory, Japan

[1] Mudstones are low-permeability sedimentary rocks; however, when shear stresses induced by tectonic movement or nonhydrostatic stresses exceed the shear strength of the rock, brittle or ductile deformation occurs. The nature of this deformation is controlled by the brittleness of the mudstone. If brittle deformation occurs, the resulting dilatant structures may increase the permeability and change the transport properties of the strata. This paper addresses the relationships among brittleness, deformation behavior, and transport properties in mudstones at the Horonobe Underground Research Laboratory, Japan. Geological, mechanical, and hydrogeological data from borehole investigations and laboratory tests were systematically interpreted using a brittleness index (BRI), which is the ratio of the unconfined compressive strength to the effective vertical stress. For mudstones under natural strain rates and low temperatures, ductile deformation occurs when BRI 8, although semibrittle behavior may also occur at the brittle-ductile boundary. When BRI >8 and faulting is well developed, the mudstone behaves hydrogeologically as a fractured medium at the mesoscopic scale, whereas for BRI <8 the mudstone behaves hydrogeologically as a porous medium, even if faulting is extensive. The BRI concept is a useful tool for systematically characterizing the hydromechanical behavior of mudstones; for example, when assessing the effectiveness of mudstone as a long-term barrier in disposal repositories for radioactive waste.

Entrance Pressure of Oil-Based Mud Into Shale

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 116364, "Entrance Pressure of Oil-Based Mud Into Shale: Effect of Shale, Water Activity, and Mud Properties," by Andres Oleas, SPE, Collins E. Osuji, SPE, Martin E. Chenevert, SPE, and Mukul M. Sharma, SPE, University of Texas at Austin, originally prepared for the 2008 SPE Annual Technical Conference and Exhibition, Denver, 21-24 September. The paper has not been peer reviewed. Oil-based muds (OBMs) have been developed to combat drilling problems often caused by shale hydration. Therefore, it is of utmost importance to understand the interaction of OBMs as they contact shales. The full-length paper deals with the movement of the oil phase of the OBM, as described by its hydraulic "entrance pressure." Although the oil filtrate of the OBM does not hydrate the shale, it can penetrate and flow into the shale at a certain entrance pressure. Such flow into shale increases the pore pressure of the shale, which can cause wellbore failure. Introduction Shales are low-permeability sedimentary rocks with small pore radii that have medium-to-high clay content, in addition to other minerals such as quartz, feldspar, and calcite. The distinguishing features of shale are its clay content and low permeability, which results in poor connectivity through narrow pore throats. Shales also are fairly porous and normally are saturated with formation water, with several factors affecting their properties, such as burial depth, water activity, and the amount and type of minerals present. Considering the fact that shales account for 70 to 75% of the formations drilled around the world, it is important to understand and minimize shale-related problems while drilling. Drilling performance has demonstrated the effectiveness of OBMs in combating drilling problems caused by shale hydration, differential-pressure sticking, corrosion, and high formation temperatures. OBMs are water-in-oil emulsions that contain water, emulsifiers, organophilic clay, and a weighting material. The water phase is usually a calcium chloride (CaCl2) salt solution, with a water activity (aw) that resembles the aw of the formation. This eliminates water transfer to or from the water-sensitive zones and, thereby, maintains a stable wellbore. The water in the oil is stabilized with a primary emulsifier (often a fatty-acid salt), while the weighting material and the drilled solids are made oil-wet and are dispersed in the mud with a secondary emulsifier. It is thought that both emulsifiers have dual roles, with the primary emulsifier also acting to some extent as a wetting agent and the secondary emulsifier acting as a true emulsifier. Ions that are added to a water-based mud (WBM) reduce the aw of the fluid, and consequently, water movement into the shale is reduced because of osmotic effects. This effect is not long lasting because the hydrated ions are not very restricted and they invade the low-salinity shale. However, for OBMs, an efficient membrane exists around each water droplet, and very little (if any) ion transfer occurs.

Geophysical methods for locating groundwater in low permeability sedimentary rocks: examples from southeast Nigeria

Geophysical techniques have long been used to help locate rural groundwater supplies in crystalline basement environments. However, as local communities (particularly in sub-Saharan Africa) look to increasingly marginal aquifers for supply, many of the standard procedures for locating groundwater become inappropriate. Areas underlain by low permeability sediments (such as shales and siltstones) are particularly difficult for locating groundwater resources. In response to these difficulties, this study was commissioned to assess both the groundwater potential and methods for siting wells and boreholes in low permeability sediments in Oju, southeast Nigeria. The Oju area suffers from an acute water shortage during a five-month dry season. Low permeability Cretaceous shales, siltstones and sandstones, with occasional intrusions of basic igneous rocks, underlie the area. Three main targets for groundwater have been identified: (i) sandy units within the shales; (ii) fracture zones in areas where the shales are lithified; and (iii) fractures associated with dolerite dykes and sills. The geophysical techniques used to identify these groundwater targets comprise frequency domain conductivity using the Geonics EM34, vertical electrical resistivity sounding (VES) and magnetic profiling (using a proton precession magnetometer). Three areas were studied in detail using a combination of geophysical surveys, exploratory drilling of the characteristics geophysical anomalies identified and test pumping. In the interbedded shale and sandstone areas, sandstones were distinguished as low conductivity zones (< 20 mmhos m −1) using electromagnetic and resistivity techniques. In the lithified mudstones, fracture zones were readily identified using electromagnetic methods as negative anomalies or smaller amplitude ‘noisy’ profiles. Dolerite intrusions wihin soft shales were identified by their lower electrical conductivity and distinct magnetic anomalies.

Hydrofracturing and Episodic Fluid Flow in Shale-Rich Basins-A Numerical Study

Low-permeability sedimentary rocks commonly are fractured. Direct examination of exposed rock faces and drill cores shows evidence of hydrofracturing. The mechanism for hydrofracturing, its effects on fluid migration, and its dependence on sediment permeability, sedimentation rate, and sedimentary sequences have not been explored. In this study we carry out systematic numerical experiments to study the compaction-induced hydrofracturing. We show that the compaction-induced hydrofracturing commonly may occur in shale-rich basins and in sand-shale sequences; the frequency of such hydrofracturing depends on sediment permeability, sedimentation rate, and sedimentary sequence. An important result is that compaction-induced hydrofracturing may occur at relatively shallow depths in shale-rich basins, but it may mobilize enhanced fluid flow throughout the sedimentary basin. Over 60% of the total compaction-induced fluid flow in the basin may be expelled during hydrofracturing. We test the model against field data from the Yinggehai basin of the south China margin, where abundant hydrofractures in the uppermost Quaternary marine mud have been recently detected by seismic imaging. We suggest that the compaction-induced hydrofracturing may mobilize fluid flow at great depths and affect hydrocarbon migration in shale-rich basins.

Technical and economic feasibility of CO 2 disposal in aquifers within the Alberta sedimentary basin, Canada

A three year study of the technical and economic feasibility of aquifer disposal of CO 2 in the low permeability sedimentary rocks of the Alberta Basin has revealed several new generic concepts that may be applicable to other sedimentary basins throughout the world. High permeability aquifers are not necessarily required for CO 2 disposal. Injectivity of CO 2 can be maximized by siting disposal wells in targeted or “sweet” zones of locally high permeability surrounded by a low regional scale permeability [1–2]. The low regional permeability forms a “hydrodynamic” or “time” trap for CO 2 [1], where the residence time of CO 2 in the aquifer is of the order of 10 5 to 10 6 years. Another type of hydrodynamic trapping in sedimentary basins is produced by the “sponge” or “sink” effect of rebounding shales [3–4]. On a smaller time scale, over hundreds of years, “mineral” or “inert” trapping [5–6] by reaction of the CO 2 with basic aluminosilicate minerals will occur in siliciclastic aquifers. Consequently, stratigraphic traps may not be necessary for safe disposal of CO 2 in the subsurface. Aquifer disposal of CO 2 is expensive, on the order of $52/tonne. Although there are many possibilities to reduce CO 2 emissions that are more economically attractive, aquifer disposal remains as one of the largest sinks available for CO 2 in landlocked areas of the world; and may be utilized if other less expensive options are exhausted.

Fluid flow in sedimentary basins

The pore waters in sedimentary basins are ultimately derived from sea water, meteoric water, mineral bound water, or from the underlying basement. Geochemically these waters initially have different signatures; however, the pore water compositions are easily altered by reactions with minerals or by mixing with other fluids. Meteoric water is driven downwards into sedimentary basins by the gravitational potential, which approximately corresponds to the elevation of the ground water table above the sea or lake level. It is difficult to model such flow, however, because the permeability on a large scale is almost impossible to represent realistically. The continuity of confined sandstone and limestone aquifers plays an important role in determining the flux of meteoric water received by rocks in different parts of the basin, but this is again difficult to predict. Pore water flow driven by compaction typically has velocities several orders of magnitude lower than what is commonly found in meteoric water flow regimes. The average rate of upwards flow is lower than the rate of subsidence and the difference is the rate of incorporation of sea water in the topmost layer at the sea floor. The salinity of formation water provides important constraints on fluid flow in sedimentary basins. In the North Sea Basin and the Gulf Coast Basin, these types of data indicate that vertical mixing by compaction-driven flow and convection is limited. Compaction-driven flow obeys Darcy's Law but there are complex interdependencies between pressure, permeability and compaction. Given the low compressibility of water, the flow which can result from pressure release alone is very limited, except on a local scale along permeable faults and fractures. The main flow of pore water during burial is driven by compaction, which is a slow process, even when overpressure is released abruptly with a resulting increase in the net effective stress. In the case of high permeability faults, the flow into the fault from low permeability sedimentary rocks at depth may be rate-limiting. The displacement of pore water in adjacent sediments near the top of the faults may also slow down fluid flow on fractures that do not reach the sea floor. Modelling of fluid flow in sedimentary basins should be based on permeability distributions which are mostly determined by primary facies, diagenesis and the tectonic history of the basin. Extensional tectonics produce a predominantly vertical fracture network which may serve as conduits for pore water flowing deep into the crust. Upward flow of hot fluids in basement fractures must have a high velocity in order to produce large thermal anomalies. Concentrations of dissolved components precipitate at the surface and form deposits of quartz and ore minerals. If basement fractures are overlain by a thick sequence of soft sediments, the rate of flow on the fractures will be reduced because of the low permeability in the sedimentary cover, and conductive heat transport will dominate. Flow of water at high enough velocities to bring hot water to the surface and produce hot springs is most likely to occur in fractured basements rocks or well-cemented sedimentary rocks. Concentrated precipitation of dissolved components will occur near the surface, where the rate of cooling is highest. Also, sediment-hosted ores precipitated from flow of hot water on fractures are therefore likely to form before accumulation of thick overlying sedimentary sequences.

Elmworth Gas Field, Alberta, Canada: Depositional Environments and Diagenetic Consideration of Low Permeability Gas Reservoir: ABSTRACT

Elmworth is a giant gas field in low permeability sedimentary rocks and is considered part of the Deep Basin in Alberta, Canada. Gas production is obtained mostly from conglomerates with unusually high permeability but with some difficulties in producing from lower permeability zones. The study of Falher conglomerate and sandstone (Lower Cretaceous) reveals that this low permeability gas reservoir owes its origin to an unique combination of depositional environments and diagenetic processes. A detailed study of Falher A and B units shows that sediments were deposited during a regression in the following coastal environments: beach, shore, lagoon-bay, coastal plain, and fluvial. Cyclic patterns of vertical sequences indicate an oscillating shoreline and five such sequences are recognized. Conglomerate and coarse sandstone occur in beach facies, while fine sandstone rich in detrital clays and organic matter predominates in shore facies. Detrital dolomite is characteristically distributed in shore facies and this is taken to indicate the direction of transport. Conglomerate and sandstone are overlain by carbonaceous shale and coal deposited in a swamp environment. Vitrinite reflectance data indicate that the sediments were subjected to deep burial and associated important diagenetic processes. Authigenic minerals are found to be most significant in Falher sediments. Quartz in the form of overgrowths and microcrystalline crystals is most extensively developed in sand-supported conglomerates and mineralogically mature sandstones in various environments. Kaolinite is predominant in most conglomerates and in sandstone, which show high primary porosity and permeability. Illite is more common in sandstone than in conglomerate though this trend is obscured by detrital clays in shoreface sandstone. Carbonate cement, mostly calcite and dolomite, is important, as it reduces porosity drastically. Diagenetic processes are strongly related to the depositional environments and their study is important not only in understanding the nature of the reservoir but in delineating the reservoir uality. End_of_Article - Last_Page 1010------------