Source: http://www.saltworkconsultants.com/blog/tag/seal_capacity/
Timestamp: 2019-04-21 09:03:51+00:00

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So far we have looked at gas distribution and origins in evaporites at micro and mesoscales and have now developed sufficient understanding to extrapolate to the broader scale of architecture for a large body of salt in an evaporite. We shall do this in a classification framework of extrasalt versus diagenetic periphery versus intrasalt gas in a halokinetic salt mass (Figure 1).
The gas inflow from this type of extrasalt breach in a salt mine is typically accompanied, or followed by, a brine release that sometimes cannot be plugged, even by a combination of grouting and brine pumping. Brine inflow rates in this scenario tend to increase with time as ongoing salt dissolution is via ongoing undersaturated water crossflows and the mine or the shaft is ultimately lost to uncontrollable flooding of gas blowouts in an oil well with poor pressure control infrastructure and planning. This type of edge intersection is why a number of early attempts to construct shafts for potash mines in western Canada failed in the middle of last century. It is why freeze curtains are considered the best way to contract a shaft for a potash mine. Examples of this type of gas/brine intersection are usually tied to telogenetic fluid entry from substantial aquifer reservoirs outside the main salt mass and are discussed in detail in Warren, (2016, Chapter 13) and as a type of salt anomaly association discussed in Warren (in press).
The extrasalt source and potential inflow volume of this form of gas (mostly methane and co-associated brine) is largely tied to maturity of hydrocarbon source rocks located external to the salt mass in both suprasalt and subsalt positions (Figure 1). In the past, unexpected extrasalt intersections of pressurised gas reservoirs during oil well drilling lead to spectacular blowouts or “gushers”, especially in situations where the salt held back a significant volume of fluid held in open fractures beneath or adjacent to a salt seal (Table 1). The fluid-focusing effects of suprasalt dome drape and associated extensional falling and gas leakage also mean “gas clouds” are common above salt domes (Warren, 2016, in press). Low σhmin leads to upward gas migration through fracturing (Dusseault et al., 2004). So, in the supradome extrasalt position, simultaneous blowout and lost circulation conditions can be encountered, as well as the problem of severely gas-cut drilling fluids. The volumes of gassy liquids held in pressurised extrasalt reservoirs can be substantial so blowouts or “gushers” can be difficult to control, as was the case with the world-famous subsalt Qom (1956) and suprasalt Macondo (2010) blowouts (Table 1). Methane and gassy liquids generated by organic maturation tend to be the dominant gases found in this situation.
This style of gas occurrence is in part related to gases sourced in maturing extra-salt sediments but also taps gases that are the result of the diagenetic processes that create caprocks. Caprocks are alteration and dissolution haloes to both bedded and halokinetic salt masses and so are distinct gas reservoirs compared to extrasalt sediments (Warren, 2016; Chapter 7). They are compilations of fractionated insolubles left behind at the salt dissolution interface as the edge of halite mass liquefies. Accordingly, caprocks are zoned mineralogically according rates of undersaturated fluid crossflow and in part responding to variable rates of salt rise and resupply. Anhydrite (once suspended in the mother salt) accretes at the dissolution front. Ongoing undersaturated crossflow at the outer contact of the anhydrite residue carapace alters anhydrite to calcite via bacterially- or thermochemically-driven sulphate reduction, with hydrogen sulphide as a by-product. Additional sulphate reduction can occur in the extrasalt sediment both at or near the caprock site, but also deeper or more distal positions in the extrasalt, so sulphate reduction can be a major source of the H2S gas found in the salt periphery. H2S can also migrate in a c from sulphate reduction in maturing sediments located some depth below the salt.
Many salt mine problems in Germany in the early days of shaft sinking for salt mining were related to unexpected shallow gas outflows confronted within caprock-hosted gas-filled vugs and fractures encountered by the mine shaft on the way to a potash ore target (Gropp, 1919; Löffler, 1962; Baar, 1977). Likewise, the highly unpredictable distribution of gases in the shallow caprocks and salt peripheries of the US Gulf Coast were the cause of some spectacular blowouts such as Spindletop (1901) (Table 1). Because the volume of held liquids is more limited in the vugs and fractures in a caprock compared to fractured subsalt reservoirs, the rate of fluid escape in a “caprock-fed” gusher tends to lessen and even self-bridge more rapidly than when salt is sealing a fractured overpressured subsalt reservoir (days or weeks versus months). As such these intersections, if isolated from extrasalt reservoirs as not such a problem in the drilling of oil wells. In simpler, less environmentally conscious, early days of oilwell drilling in East Texas in the 1920s, “gushers” were often celebrated, tourist spots and considered a sign of the potential wealth coming to the country being drilled.
This type of accumulation/intersection is often described as an intrasalt gas pocket and is typified by a high rate of gas release, that in a mine is accompanied by a rockburst, followed by a waning flow that soon reaches negligible levels as the pocket drains (see article 1 in this series). Intrasalt gas pockets can create dangerous conditions underground and lives can be lost, but in many cases after the initial blowout and subsequent stabilisation, the mine operations or oil-well drilling can continue. Gas constituents and relative proportions are more variable in intrasalt gas pockets compared to gases held in the extrasalt and the periphery. Extra-salt gases are typically dominated by methane with lesser H2S and CO2, periphery gases by H2S and methane, while intrasalt gases can be dominated by varying proportions of nitrogen, hydrogen or CO2. Methane can be a significant component in some intrasalt gas pockets, but these occurrences are usually located in salt anomalies or fractures that are in current or former connection with the salt periphery.
The type of gas held within and about a salt mass in a sedimentary basin is broadly related to position in the mass and proximity to a mature source rock. Herein is the problem, most of the gases that occur in various salt-mass related positions (intrasalt, extrasalt and periphery) can have multiple origins and hence multiple sources.
Accumulations of gas with more than 95 vol.% N2 are found in most ancient salt basins and the great majority of these accumulations are hosted in intersalt and subsalt beds, with the gas occurring in both dispersed and free gas forms in the salt, as in many Zechstein potash mines of Germany and the Krasnoslobodsky Mine in the Soligorsk mining region of Russia (Tikhomirov, 2014). Nitrogen gas today constitutes around 80% of earth atmosphere where it can result from the decay of N-bearing organic matter (proteins). Ultimately, nitrogen speciates from aqueous mantle fluids in oxidised mantle wedge conditions in zones of subduction and in terms of dominance in planetary atmospheres it indicates active plate tectonics (Mikhail and Sverjensky, 2014). Nitrogen in the subsurface is large unreactive compared to oxygen and so tens to stay in its gaseous form while oxygen tens to combine into a variety of minerals. When held in a salt bed, nitrogen can be captured from the atmosphere during primary halite precipitation and stored in solution in a brine inclusion so creating a dispersed form of pressurised nitrogen. When buried salt recrystallizes during halokinesis, with flow driven by via pressure solution, inclusion contents can migrate to intercrystalline positions and from there into fractures to become free gas in the salt.
Methane gas captured in and around a salt mass as both dispersed and be gas typically mostly comes from organic maturation. The maturing organic matter can be dispersed in the salt during primary halite precipitation, it can be held in intersalt source beds (as in the Ara Salt of Oman), or it can migrate laterally to the salt edge, along with gases and fluids rising from more deeply buried sources. Thus, the presence of oil, solid bitumen and brine inclusions, with high contents of methane in halite, does not unequivocally point to the presence of oil or gas in the underlying strata, it can be locally sourced from intersalt beds as in the Ara Salt. However, a geochemical aureole can be said to occur if hydrocarbons in the halite-hosted inclusions can genetically be linked with reservoired oil or gas. The presence of methane in salt anomalies in Louann Salt mines in the US Gulf Coast and some mines in Germany is likely related to organic maturation of deeply buried extrasalt source rocks with subsequent entrapment during halokinesis and enclosure of allochthon-suture sediments.
Hydrogen sulphide gas (H2S) is a commonplace free gas component in regions of bacterial and thermogenic sulphate reduction. Like methane, much of its genesis is tied to organic maturation products (and sulphate reduction processes), and like methane, it can be held in salt seal traps, or in peripheral salt regions, or in intrasalt and intersalt positions and like metyhane if it escapes and ponds in an air space its release can be deadly (Table 1; Luojiazhai gas ﬁeld, China). Because both bacterial and thermochemical sulphate reduction requires organic material or methane, there is a common co-occurrence of the two gases. Caprock calcite phases are largely a by-product of bacterial sulphate reduction, so there is an additional association of H2S with caprock-held occurrences. This form of H2S, along with CO2, created many problems in the early days of shaft sinking in German salt mines. More deeply sourced H2S tend to be a production of thermochemical sulphate reduction in regions where pore fluid temperatures are more than 110°C.
Detailed study of CO2 and its associated geochemical/mineralogic haloes shows much of the CO2 held in Zechstein strata of Germany has two main sources; 1) Organic maturation and 2) carbonate rock breakdown especially in magmatic hydrothermal settings (Fischer et al., 2006). The organic-derived CO2 endmember source (with δ13C near -20‰) is present in relatively low concentrations, whereas large CO2 concentrations are derived from an endmember source with an isotope value near 0‰. Although the latter source is not unequivocally defined by its isotopic signature, such “heavy” CO2 sources are most likely attributed to heating-related carbonate decomposition processes. This, for example, explains the CO2-enriched nature of salt mines in parts if the former East Germany where Eocene intrusives are commonplace (Shofield et al., 2014).
Hydrogen (H2) gas distribution as a major component varies across salt basins and is especially obvious in basins with significant levels of carnallite and other hydrated potassic salts. This association leads to elevated radiogenic contents tied to potassic salt units, with hydrogen gas likely derived from the radiogenic decomposition of water (see article 2 in this series). The water molecules can reside in hydrated salts or in brine inclusions in salt crystals.
Various proportions of gases (N2, CH4, CO2, H2S, H2) held in salt as dispersed and free gas occur in all salt basins. But at the broad scale, certain gases are more common in particular basin and tectonic positions. Methane is typically enriched in parts of a basin with mature source rocks, but can also have a biogenic source. Likewise, H2S is tied to zones of organic breakdown, especially in zones of either bacterial or thermochemical sulphate reduction. CO2 can occur in salt in regions of organic degradation, but is most typical those of parts of a salt basin where igneous processes have driven to thermal and metamorphic decomposition of underlying carbonates (including marbles). Nitrogen because of its inert nature is a commonplace intrasalt gas and comes typically from zones of organic decomposition with dispersed nitrogen becoming free gas with subsequent halokinetic recrystallisation. Ongoing salt flow can drive the distribution of all dispersed salt stored gases into free gas (gas pocket) positions.
Baar, C. A., 1977, Applied salt-rock mechanics; 1, The in-situ behavior of salt rocks: Developments in geotechnical engineering. 16a.
Clayton, C. J., S. J. Hay, S. A. Baylis, and B. Dipper, 1997, Alteration of natural gas during leakage from a North Sea salt diapir field: Marine Geology, v. 137, p. 69-80.
Dusseault, M. B., V. Maury, F. Sanfilippo, and F. J. Santarelli, 2004, Drilling around salt: Stresses, Risks, Uncertainties: Gulf Rocks 2004, In 6th North America Rock Mechanics Syposium (NARMS), Houston Texas, 5-9 June 2004, ARMA/NARMS 04-647.
Fischer, M., R. Botz, M. Schmidt, K. Rockenbauch, D. Garbe-Schönberg, J. Glodny, P. Gerling, and R. Littke, 2006, Origins of CO2 in Permian carbonate reservoir rocks (Zechstein, Ca2) of the NW-German Basin (Lower Saxony): Chemical Geology, v. 227, p. 184-213.
Mikhail, S., and D. A. Sverjensky, 2014, Nitrogen speciation in upper mantle fluids and the origin of Earth's nitrogen-rich atmosphere: Nature Geoscience, v. 7, p. 816-819.
Tikhomirov, V. V., 2014, Molecular nitrogen in salts and subsalt fluids in the Volga-Ural Basin: Geochemistry International, v. 52, p. 628-642.
Warren, J. K., in press, Salt usually seals, but sometimes leaks: Implications for mine and cavern stability in the short and long term: Earth-Science Reviews.
This, the third article in the series of four on salt leakage, discusses how and when salt acts as a seal. The fourth article will place this discussion in real world situations where the various salt units (especially “dark” salt) have lost long-term seal integrity and what this means in terms of CO2 geosequestration and waste storage.
Unlike thick shales, subsurface evaporites in the diagenetic realm better fit Hunt’s (1990) definition of an actual pressure seal, which he defined as an impermeable rock with zero transmissivity maintained over long periods of geologic time. Very little subsalt fluid can escape through a salt mass that, until breached, tends to hold back all the compactional and thermohaline waters, gases or liquid hydrocarbons rising from below. In contrast, shale-seals consistently leak all these fluids to varying degrees.
In the realm of subsurface hydrocarbon exploration and development, salts (especially halite) are second only to clathrates in ability to form an effective seal to circulating pore waters and hydrocarbons, including methane. (Figure 1; Warren, 2016). Natural methane clathrates (methane-ice mixtures) are more efficient seals, but in the diagenetic realm, clathrate occurrence is limited by the inherent low-temperature stability requirement. This means clathrates act as hydrocarbon seals onshore in permafrost regions, such as some Siberian gas fields, or below clathrate layers down to depths of a hundred meters or so beneath the modern deep-sea floor, as occurs below the cold waters of the slope and rise across the halokinetic Gulf of Mexico or the non-halokinetic sediment of offshore Brunei (Warren, 2016; Warren et al., 2011a).
Like clathrates, evaporite layers can generate overpressures at very shallow burial depths, unlike clathrates they do not dissolve and dissipate in response to rising temperatures of the diagenetic burial realm. Evaporites create the highest and sharpest depth-related pressure differentials known in sedimentary basins in both overpressured and underpressured settings (Fertl 1976). Salt-sealed overpressured intervals can be as shallow as a few hundred meters below the surface or deeper than 6,000 m.
Unlike the low temperatures requirements for a clathrate seal, evaporite seals, with their extremely high entry pressures, ductility, very low permeabilities and large lateral extents, can maintain seal integrity over wide areas, even when exposed to a wide range of subsurface temperature and pressure conditions. A typical shale seal has permeability ≈ 10-1 to 10-5 md, with extreme values as low as 10-8 md (Figure 2). Quantitative measurement of evaporite permeability is beyond the capacity of standard instruments used in the oil industry and is mostly a topic of study for engineers working with waste-storage caverns. Their work shows the permeability of undisturbed halite is a nanodarcy or less, that is, undamaged subsurface salt has measured permeabilities that are less than 10-21 m2 (10-6md) with some of the tighter halite permeabilities ≈10-7 to 10-9 md. In contrast, typical massive anhydrites ≈10-5 md (Beauheim and Roberts, 2002). This explains a general “rule of thumb” used in the oil industry that a halite bed should be at least 2 m thick to be considered a possible seal, while and anhydrite bed should be at least 10 m thick. Equally important is the reliability of the geological model of the evaporite that is used to extrapolate lateral continuity in the seal (Warren, 2016). Pore pressures in thick sealing halites can approach lithostatic (Ehgartner et al., 1998) and when exceeded salt can locally fracture and leak (as discussed in the previous article).
Massive thick bedded pure halite units in the diagenetic realm usually contain few, if any, interconnected pore throats. The distance between NaCl lattice units is 2.8 x 10-10 m, while the smallest molecular diameter of a hydrocarbon molecule (methane) is 3.8 x 10-10 m. The most frequent way that hydrocarbons migrate through an unfractured undissolved halite bed is if the halite contains impurities that render it locally porous and make it brittle during deformation.
Halite’s very high ductility and its ability to flow, re-anneal and re-establish lattice bonding by solution creep when subject to stress give it a low susceptibility to fracturing even when it is deforming (Figure 3). This is why cross-salt fault and fracture patterns, as seen in most salt-entraining basins, make the industry considers salt a “crack-stopper” (Figure 4). Worldwide, seismic imaging of halokinetic realms shows that the salt has flowed, while adjacent carbonate and siliciclastics sequences fractured. Halite’s ability to maintain seal integrity under stress, and so prevent the escape of hydrocarbons, reflects a combination of an ability to flow and re-anneal, and the small size of molecular interspaces in its ionically-bonded NaCl crystal lattice (Figure 5; see detailed discussion see Warren, 2016, chapters 6 and 10).
This propensity to flow under stress (tendency toward Newtonian flow) is why many laboratory tests and measurements consistently under-represent salt’s flow and subsurface seal integrity responses. Inherently any lab experiment is tied to short time frames of up to weeks or a few years. However, such laboratory tests are likely more relevant to real-world subsurface situations where salt in the vicinity of any wellbore is damaged by the nearby passage of the drill bit and its associated fluids. The applicability of laboratory measurements to real-world subsurface situations is a philosophical quandary inherent to many natural science experiments with a time-related possible-error component. By putting equipment into a natural subsurface salt region, or by removing salt samples from their natural deep subsurface environment to take measures in the lab, or by growing salt crystals in the lab to work on, we always alter things and so get outcomes that can never be 100% accurate with respect to the original unaltered subsurface salt setting. That is, within observational errors, how do we quantify random versus systematic errors when we are always altering the samples and the surrounds via the process of gaining access?
Whether, during catagenesis, buried halite beds that enclose organic intrabeds can release volatiles to sediments outside the salt mass is still a matter of some discussion among organic geochemists. The long-term lack of fracture or pore throats in buried salt beds is why organic-rich intrasalt carbonate or shale laminites tend to be inefficient source rocks in style 1a source rocks (Warren et al., 2011a). Likewise, possible flushing and maturation effects are poorly understood in subsurface situations where encased organic-rich beds are in contact with hydrated salts converting to their anhydrous equivalents (such as gypsum to anhydrite or carnallite to sylvite, mirabilite to thenardite). Loss of water of crystallisation in shallow burial (<0.5km) has the potential to allow organic-rich fluids to escape early as the hydrated salts transform to their anhydrous forms. Usually, such burial transformations are near complete in the first kilometre of burial and so may only allow immature hydrocarbons to escape into adjacent more porous sediments (Hite and Anders, 1991). There they must be stored, mature and remigrate during later burial if they are to act as hydrocarbon source rocks (Warren, 1986). Many intrasalt organic-rich beds survive well into the metamorphic realm and evolve into graphitic quartzites and marbles encased in meta-evaporitic albitites and scapolites.
As a general rule, even as a halite bed fractures, its inherent lack of strength and the consequent ability to flow means any microscale intercrystalline fractures quickly re-anneal by a combination of flow and pressure-solution induced recrystallisation. (Figure 5). Current consensus in the oil and gas industry is that some thin impurity-rich salt beds, interlayered with carrier beds, do leak small amounts of volatiles, but much less efficiently than thicker organic-rich mudstones and shales; whereas organics encased in thicker salt beds probably cannot leak from the unit until the enclosing salt dissolves or natural hydrofracturing occurs (as in the Ara Salt of Oman). Evaporite beds and salt allochthons constitute some of the strongest long-term subsurface barriers to the vertical migration of hydrocarbons in a sedimentary basin both as a seal to hydrocarbons and in CO2 sequestration.
The next and final article in this series on salt leakage will consider; how and where does a salt seal leak in the real world of the subsurface?
Beauheim, R. L., and R. M. Roberts, 2002, Hydrology and hydraulic properties of a bedded evaporite formation: Journal of Hydrology, v. 259, p. 66-88.
Downey, M. W., 1984, Evaluating seals for hydrocarbon accumulations: Bulletin American Association of Petroleum Geologists, v. 68, p. 1752-1763.
Fertl, W. H., 1976, Abnormal Formation Pressures: Amsterdam, Elsevier Scientific, 382 p.
Hite, R. J., and D. E. Anders, 1991, Petroleum and evaporites, in J. L. Melvin, ed., Evaporites, petroleum and mineral resources, v. 50: Amsterdam, Elsevier Developments in Sedimentology, p. 477-533.
Hunt, J. M., 1990, Generation and migration of petroleum from abnormally pressured fluid compartments: Bulletin American Association of Petroleum Geologists, v. 74, p. 1-12.
Ter Heege, J. H., J. H. P. De Bresser, and C. J. Spiers, 2005, Dynamic recrystallisation of wet synthetic polycrystalline halite: dependence of grain size distribution on flow stress, temperature and strain: Tectonophysics, v. 396, p. 35-57.
Urai, J. L., Z. Schléder, C. J. Spiers, and P. A. Kukla, 2008, Flow and Transport Properties of Salt Rocks, in R. Littke, ed., Dynamics of complex intracontinental basins: The Central European Basin System, Elsevier, p. 277-290.
Warren, J. K., 1986, Shallow water evaporitic environments and their source rock potential: Journal Sedimentary Petrology, v. 56, p. 442-454.
Warren, J. K., 2011b, Evaporitic source rocks: mesohaline responses to cycles of “famine or feast” in layered brines, Doug Shearman Memorial Volume, (Wiley-Blackwell) IAS Special Publication Number 43, p. 315-392.
Warren, J. K., A. Cheung, and I. Cartwright, 2011a, Organic Geochemical, Isotopic and Seismic Indicators of Fluid Flow in Pressurized Growth Anticlines and Mud Volcanoes in Modern Deepwater Slope and Rise Sediments of Offshore Brunei Darussalam; Implications for hydrocarbon exploration in other mud and salt diapir provinces (Chapter 10), in L. J. Wood, ed., Shale Tectonics, v. 93: Tulsa OK, AAPG Memoir 93 (Proceedings of Hedberg Conference), p. 163-196.

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