Salty Matters

The Blog is written by me, John Warren. Once every three or four weeks or so I will post an article or two on an evaporite topic that has piqued my interest. On the Saltwork Publications webpage (under "the Works") there is a growing library of pdfs and epubs based on these blogs. These articles on the website have much higher resolution extractable graphics in than in the blog. There is also a link to this set of pdfs and epubs on the home page (www.saltworkconsultants.com).

Salt as a Fluid Seal: Article 3 of 4: When it doesn't leak - Seals to hydrocarbons

John Warren - Saturday, March 12, 2016

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.

Evaporite seal character

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.

 


 

Seal capacity in flowing pure salt

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 COsequestration.

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?

References

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.

Ehgartner, B. L., J. T. Neal, and T. E. Hinkebein, 1998, Gas Releases from Salt: SAND98-1354, Sandia National Laboratories, Albuquerque, NM, June 1998.

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., 2016, Evaporites: A compendium (ISBN 978-3-319-13511-3) Released Feb. 2016: Berlin, Springer, 1854 p.

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.

 

 

 

 

 

 

Salt as a Fluid Seal: Article 2 of 4: Internal fluid source

John Warren - Wednesday, January 20, 2016

 

Black Salt: as an indicator of overpressure

The previous article in this series on salt leakage focused on black and dark salt created by ingress or interaction of undersaturated waters with relatively shallow halokinetic salt masses, with entry zones often tied to intervals of salt shear. The resulting black or dark salt textures are one style of “anomalous” salt. This article looks at fluid entry into salt in subsurface intervals of high pore pressure, exemplified by the “black salt” in the Ara salt seals of Oman. Such intervals are often tied to burial-pressure and temperature-related changes to the dihedral angle of salt (halite).


Dihedral angle changes and the permeability of salt

Permeability in intercrystalline pore networks in re-equilibrating and crystallising subsurface salt is tied to the dihedral angle  at solid-solid-liquid triple junctions (Figure 1; Lewis and Holness, 1996, Holness and Lewis, 1997). When the halite dihedral angle is higher than 60° under static laboratory conditions, this contact angle equates to the maintenance of closure of polyhedral grain boundaries by halite precipitation, and so at these lower temperatures both bedded and halokinetic recrystallized salt is impermeable (Schenk and Urai, 2004; Holness and Lewis, 1996). In this temperature range, the small amount of brine present in the salt is distributed in micrometer-sized isolated fluid inclusions at termini of salt crystal polygon apices. In contrast, when the solid-solid-liquid interfaces of increasingly heated and pressurised polyhedral halite attain dihedral angles that are less than 60° then the fluid-inclusion filled intercrystal cavities link up and the salt mass becomes permeable.


At burial temperatures >100°-150°C and pressures of 70 MPa or more, the dihedral angle has decreased to values <60°, driving a redistribution of the fluid into a thermodynamically stable network of connected, fluid-filled channels or fused fluid strings at grain boundary triple junctions. This transition may be related to the observation by Peach and Spiers (1996) that, during natural deformation of rocksalt at great depths, salt undergoes natural hydraulic fracturing or dilatancy. The dihedral angle is, therefore, a thermodynamic property that changes with pressure P and temperature T. Holness and Lewis’s experiments demonstrated that buried salt masses, subject to high pressures and elevated temperatures, can acquire intercrystalline or polyhedral permeability comparable to associated with intergranular permeability in sand.

This typically occurs at higher temperatures and pressures where intercrystal water positions link within flowing or static, but texturally re-equilibrated, salt and so creates continuous fluid strings along evolving intercrystalline junctions in the burial-recrystallised salt. The newly attained intercrystal configuration allows penetration and throughflow of hot, dense brines or hydrocarbons into and through the altered mass of salt polyhedrons. In Oman has created characteristic haloes of black salt about pressurised salt-encased carbonate slivers (next section).

At the same time as a recrytallising salt mass passes into the earlier stages of the greenschist facies, the salt is dissolving and altering to sodic scapolite (Warren, 2016; Chapter 13). Thus, through the later stages of diagenesis and into early to medium grades of metamorphism, the salt and its daughter products may act as sources and conduits for flow of chloride-rich metalliferous brines and salt slurries. This occurs as bedded and halokinetic salt evolves from a dense impermeable salt mass into permeable salt with higher dihedral angles and so explains salt’s significant role in the creation of many of massive base metal and IOCG deposits (Warren, 2016; Chapters 15, 16).


Black salt and overpressure in Oman

The transition in dihedral angle with increasing pressure and temperature explains the occurrence of black (bitumen-charged) haloes in salt encasing some carbonate-sliver reservoirs in the Ara Salt of Oman (Figure 2; Kukla et al., 2011a, b). Once this recrystallization occurs, the previous lower P&T mosaic halite loses its ability to act as an aquitard or aquiclude (seal) and can instead serve as a permeable conduit for escaping highly-pressurised and hydrocarbon-rich formation waters. According to Lewis and Holness, the depth at which the recrystallization occurs may begin as shallow as a few kilometres (Figure 1). But, their pressure bomb laboratory-based static-salt experiments did not completely encompass the ability of natural salt to pressure creep and self-seal by longer-term diffusion-controlled pressure solution (Warren 2016, Chapter 6). Even if the changing dihedral angles alter and open up permeability at such shallow depths, there is no guarantee that subsequent flowage associated with pressure solution will not re-anneal these new pores. The ability of salt to continue to act as a highly efficient hydrocarbon seal to depths of 6-10 km means, in my opinion, that bedded salt does may become a relative aquifer until attaining depths of 6-10 km or more. This occurs certainly at temperatures and pressures where the sequence is entering the greenschist realm. In extremely overpressured situations the transition of dihedral angles is much shallower, as in the 40-50m thick black salt rims that typify the salt-encased hydrocarbon-charged carbonate stringers in the Ara Salt of Oman (Kukla et al., 2011b). Once it does transform into polyhedral halite, a former aquiclude becomes an aquifer flushed by chloride-rich brines, likely carrying other volatiles.

A release of entrained inclusion (±intercrystalline) water at temperatures > 300-400°C (early greenschist) influences the textures of deeply buried halite. Most of the inclusions in chevron halite and other inclusion-rich cloudy primary salts are due to entrained brine inclusions and not mineral matter. Figure 3 plots the weight loss of various types of halite during heating. It clearly shows cloudy (inclusion-rich) halite releases up to 5 times more brine (0.2-0.5 wt%) than clear coarsely crystalline halite. An analysis of all fluids released during heating shows carbon dioxide and hydrogen contents are much lower than the water volumes: CO2/H2O < 0.01 and H2/H2O < 0.005. Organic compounds, with CH4, are always present (<0.05% H2O), and are twice as abundant in cloudy halite. There are also traces of nitrogen and, in some samples, hydrogen sulphide and sulphur dioxide (Zimmermann and Moretto, 1996).


The influence of overpressure driving changes in the dihedral angle of pressurised salt is most clearly seen in black-salt encased Late Neoproterozoic to early Cambrian intra-salt Ara (stringer) reservoirs of the South Oman Salt Basin (Figures 2, 4, 5; Kukla et al., 2011b). These carbonate bodies are isolated in salt and frequently contain low-permeability dolomites and are characterised by high initial hydrocarbon production rates due to overpressure. But not all stringers are overpressured, and a temporal relationship is observed defined by increasingly overpressured reservoirs within stratigraphically younger units. There are two separate pressure trends in the stringers; one is hydrostatic to slightly-above hydrostatic, and the other is overpressured from 17 to 22 kPa.m−1, almost at lithostatic pressures (Figure 4).


The black staining of the halite is caused by intragranular microcracks and grain boundaries filled with solid bitumen formed by the alteration of oil (Figures 2, 5). The same samples show evidence for crystal plastic deformation and dynamic recrystallization. Subgrain-size piezometry indicates a maximum differential paleostress of less than 2 MPa. Under such low shear stress, laboratory-calibrated dilatancy criteria suggest that oil can only enter the rock salt at near-zero effective stresses, where fluid pressures are very close to lithostatic. In Schoenherr et al.’s (2007b) model, the oil pressure in the carbonate stringer reservoirs reservoir increases until it is equal to the fluid pressure in the low, but interconnected, porosity of the Ara Salt, plus the capillary entry pressure (Figure 5). When this condition is met, oil is expelled into the rock salt, which dilates and increases its permeability by many orders of magnitude. Sealing capacity is lost, and fluid flow will continue until the fluid pressure drops below te minimal principal stress, at which point rock salt will reseal to maintain the fluid pressure at lithostatic values. Inclusion studies in the halite indicate ambient temperatures at the time of entry were more than 90°C, implying hydrocarbons could move into interconnected polyhedral tubes in the halite. These conduits were created in response to changes in the polyhedral angle in the halite in response to elevated temperatures (Lewis and Holness, 1996).


Hydrocarbon-stained “black salt” can extend up to 100 metres from the pressurised supplying stringer into the Ara salt of Oman (Figure 2, 5). It indicates a burial-mesogenetic pressure regime and is not the same process set as seen in the telogenetic “black salt” regions of the onshore Gulf of Mexico. The latter is created by dissolution, meteoric water entry, and clastic contamination, as in the crests of nearsurface diapirs such as Weeks Island (Warren 2015). An Ara stringer enclosed by oil-stained salt but now below the lithostatic gradient likely indicates a later deflation event that caused either complete (C) or partial (E) loss of overpressures. Alternatively, stringers showing overpressure, but below the lithostatic gradient (E), might be explained by regional cooling or some other hitherto unexplained mechanism (Figure 4a; Kukla et al., 2011a, b).

Structural, petrophysical and seismic data analysis suggests that overpressure generation in the Ara is driven initially by rapid burial of the stringers in salt, with a subsequent significant contribution to the overpressure from thermal fluid effects and kerogen conversion of organic-rich laminites with the stringer bodies. If the overpressured stringers come in contact with a siliciclastic minibasin, they will deflate and return to hydrostatic pressures (A) in Figure 4. When the connection between the minibasin and the stringers is lost, they can regain overpressures because of further oil generation and burial (A’). If hydrocarbon production in undeflated stringers stops relatively early, the fluid pressures do not reach lithostatic pressures (B). If hydrocarbon generation continues, the fluid pressures exceed the lithostatic pressure (red star), leading to dilation and oil expulsion into the rock salt to what is locally known as “black salt” (D and E).

As well as these examples of overpressure associated with older evaporites, overpressure readily develops in salt-sculpted Tertiary basins. For example, overpressure occurs in salt shear (gumbo) transitions beneath some, but not all, shallow salt allochthons in Green and Mahogany Canyon regions in the Gulf of Mexico (Beckman, 1999: Shaker 2008). Where salt allochthons are climbing the stratigraphy, subsalt sealing and associated overpressure can occur beneath the salt mass at shallower levels than is observed in overpressured shale basins.

In terms of extension and compression regimes within a single allochthon tongue, Shaker (2008) noted that in extensional regions in halokinetic basins the magnitude and direction of the principal stresses are controlled by sediment load, salt thickness, and salt emplacement-displacement history. Therefore, the maximum principal stress is not necessarily represented by the sheer weight of the overburden, as is usually assumed in quiescent terranes. Salt buoyancy often acts upward and has the tendency to accelerate and decelerate the principal stress above and below the salt, respectively. A distinctive shift of the pore pressure envelopes and normal compaction trends takes place across the salt body in several wells drilled trough salt below minibasins in the Mississippi Canyon, Green Canyon, and Garden Banks areas of the Gulf of Mexico. A lower pore pressure gradient has been observed below the salt and a higher gradient above the salt barrier. On the salt-rooted minibasin scale, a high-gradient was also observed in areas where the salt was emplaced and a lower gradient where the salt withdrew (Shaker and Smith, 2002). On the other hand, in the compressional portion of a salt allochthon system, lateral stress generated by the salt movement piling up salt at the foot of the slope acts as the maximum principal stress, whereas the load of sediment represents the minimum stress.


Extreme overpressuring is commonplace in subsalt settings in the Gulf of Mexico at depths of 3000-4000 m and its variability creates drilling problems, as evidenced by the BP Horizon spill and explosion on April 20, 2010. Gas generated at greater depths in these regions can be trapped under the salt seal at pressures approaching lithostatic. It means drilling under the allochthonous salt on the Gulf Coast slope can intersect undercompacted sediments that are moderately to extremely overpressured and friable (Hunt et al., 1998). The influence of highly effective Jurassic salt seals on pressure gradients in the Neogene stratigraphy of the Gulf of Mexico is seen in the increased mud weights typically required for safe drilling, once an evaporite allochthon is breached by the drill (Table 1). Many wells intersecting salt allochthons in the deepwater realm of the Gulf of Mexico and the circum-Atlantic Salt basins are overpressured at some depth below the base of salt with mud weights controlling pressures ranging from 14 to 17.5 ppg.

Implications

This and the previous article (Warren, 2015) demonstrate that black salt is a form of anomalous salt that indicates salt has leaked, however, the locations and conditions where leakage has occurred are distinct. The black salt encountered in the salt mines of the US Gulf Coast are indicative of meteoric water entry in relatively shallow conditions in regions where the salt is in contact with the surrounding shales of muds that enclose the diapir salt core. In other words, fluid entry is from the outside of the salt mass and fluids move into the salt from its edges and likely enhance  the porosity in the intercrystalline salt. In contrast, the black salt occurrences in the Ara Salt of Oman are indicative of overpressure haloes, generated internally via hydrocarbon and fluid expulsion in carbonate slivers, which are are fully encased in salt. This creates naturally hydrofractured envelopes in the salt mass in zones where pressure and temperature induced changes in the dihedral angle has generated intercrystalline fluid strings within the recrystallised polyhedral halite. The two settings of black salt formation are distinct.

There is not a single mechanism that creates black salt in a halokinetic salt mass. We shall discuss the implications of this in the next article which will include a look at leakage models in halokinetic salt systems both in terms of their seal integrity and the implications for short and  long term storage of hydrocarbons and nuclear waste. 

References

Beckman, J., 1999. Study reveals overpressure sources in deep-lying formations. Oil and Gas Journal, September: 137.

Holness, M.B. and Lewis, S., 1997. The structure of the halite-brine interface inferred from pressure and temperature variations of equilibrium dihedral angles in the halite-H2O-CO2 system. Geochimica et Cosmochimica Acta, 61(4): 795-804.

Hunt, J.M., Whelan, J.K., Eglinton, L.B. and Cathles III, L.M., 1998. Relation of shale porosities, gas generation, and compaction to deep overpressures in the US Gulf Coast. In: B.E. Law, G.F. Ulmishek and V.I. Slavin (Editors), Abnormal pressures in hydrocarbon environments. American Association Petroleum Geologists Memoir 70, Tulsa, OK, pp. 87-104.

Kukla, P., Urai, J., Warren, J.K., Reuning, L., Becker, S., Schoenherr, J., Mohr, M., van Gent, H., Abe, S., Li, S., Desbois, Zsolt Schléder, G. and de Keijzer, M., 2011a. An Integrated, Multi-scale Approach to Salt Dynamics and Internal Dynamics of Salt Structures. AAPG Search and Discovery Article #40703 (2011).

Kukla, P.A., Reuning, L., Becker, S., Urai, J.L. and Schoenherr, J., 2011b. Distribution and mechanisms of overpressure generation and deflation in the late Neoproterozoic to early Cambrian South Oman Salt Basin. Geofluids, 11(4): 349-361.

Lewis, S. and Holness, M., 1996. Equilibrium halite-H2O dihedral angles: High rock salt permeability in the shallow crust. Geology, 24(5): 431-434.

O'Brien, J. and Lerche, I., 1994. Understanding subsalt overpressure may reduce drilling risks. Oil and Gas Journal, 92(4): 28-29,32-34.

Peach, C. and Spiers, C.J., 1996. Influence of crystal plastic deformation on dilatancy and permeability development in synthetic salt rock. Tectonophysics, 256: 101-128.

Schenk, O. and Urai, J.L., 2004. Microstructural evolution and grain boundary structure during static recrystallization in synthetic polycrystals of sodium chloride containing saturated brine. Contributions to Mineralogy and Petrology, 146: 671-682.

Schoenherr, J., Littke, R., Urai, J.L., Kukla, P.A. and Rawahi, Z., 2007a. Polyphase thermal evolution in the Infra-Cambrian Ara Group (South Oman Salt Basin) as deduced by maturity of solid reservoir bitumen. Organic Geochemistry, 38(8): 1293-1318.

Schoenherr, J., Urai, J.L., Kukla, P.A., Littke, R., Schleder, Z., Larroque, J.-M., Newall, M.J., Al-Abry, N., Al-Siyabi, H.A. and Rawahi, Z., 2007b. Limits to the sealing capacity of rock salt: A case study of the infra-Cambrian Ara Salt from the South Oman salt basin. Bulletin American Association Petroleum Geologists, 91(11): 1541-1557.

Shaker, S., 2008. The double edged sword: The impact of the interaction between salt and sediment on subsalt exploration risk in deep water. Gulf Coast Association of Geological Societies Transactions, 58: 759-769.

Warren, J.K., 2015. Salt as a fluid seal: Article 1,  Salty Matters blog; First published on Dec 19, 2015; www.saltworkconsultants.com.

Warren, J.K., 2016. Evaporites: A compendium (ISBN 978-3-319-13511-3) Released Feb. 2016. Springer, Berlin, 1854 pp.

Zimmermann, J.L. and Moretto, R., 1996. Release of water and gases from halite crystals. European Journal of Mineralogy, 8(2): 413-422.


 

 


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