Bedded hydrocarbon traps

Saltern and deepwater evaporite beds make excellent seals because the density-stratified hydrology of their depositional setting guarantees there was little lateral variation in depositional rock properties over large areas of the salt-covered basin floor (Chapters 2 and 5). Evaporite-plugged mudflat units also make effective seals, as do platform carbonates plugged by evaporite cement precipitated from dense reflux brines. But high levels of entrained impurities, less predictable depositional topography and lateral variations in early diagenetic fluid flux rates mean that, compared to saltern and basinwide-style seals, these dirtier seal types are more subject to problems with lateral continuity, as well as showing a higher propensity for stress fracture and failure.

The primary function of bedded evaporites in the evaporite hydrocarbon association is as a seal to subsalt accumulations of oil and gas (Tables). In some cases, high levels of primary intergranular porosity in grain-dominated limestones are preserved beneath a salt seal (e.g. Jurassic Arab cycles on the Arabian Peninsula) or intercrystalline porosity fashions a variably dolomitised subsalt limestone reservoir (e.g. San Andres reservoirs on the Central Basin Platform fields of West Texas). Impermeable evaporite beds and salt-plugged dolomites capping various upward-shoaling platform cycles, effectively seal off underlying porous carbonates from later surface-driven influxes of freshwater or other suprasalt diagenetic fluids. 

A selection of Palaeozoic fields with bedded evaporite seals (from Warren, 2016; Chapter 10)
A selection of Tertiary to Tirassic fields with bedded evaporite seals (from Warren, 2016; Chapter 10)

Evaporite horizons, or any pervasively-plugged adjacent diagenetic haloes, are not potential reservoirs, unless a bed dissolves into a solution breccia, or intergranular salt cements are leached from previously salt-plugged sands or dolomites. During evaporite deposition, there is an associated hydrological system of basinward flushing dense brines (reflux). This occurs in the early stages of salt deposition and shallow burial (<100-200m burial) before the loss of intrasalt and subsalt permeability, especially where a gypsum saltern is accumulating atop a marine platform carbonate. Circulation is driven by gravitational instability, set up by an updip dense brine plume or brine curtain below accumulating evaporites (Figure). At its periphery, this refluxing plume mixes with and displaces less dense subsurface and connate waters to create or enhance the reservoir properties of adjacent subsalt limestones via reflux dolomitisation.

As dense Mg-rich brines seep downdip from the platform saltern or mudflat, they create intervals of porous dolomites in more distal zones, located seaward of overdolomitised evaporite-plugged areas. In some cases, the most extensively dolomitised carbonates in these more distal zones are high-energy, shallow water grainstones and packstones. These were the sediments with the higher permeabilities at the time of dolomitisation. However, in areas of pervasive syndepositional marine cementation, some initially porous carbonates may have already lost much of their intergranular permeability via overgrowths of isopachous rim cement. In this situation, the less cemented platform mudstones act as aquifers to the refluxing brines and so are preferentially dolomitised. Likewise, in more restricted portions of an epeiric carbonate platform where the only sediment beneath a salt seal is lagoonal mud, it is dolomitised and sometimes converted into a reservoir with intercrystalline permeability (e. g. the Levelland-Slaughter trend in the San Andres Fm, West Texas and New Mexico).

In some muddy platform carbonates, only the pelletal and sandy burrow fill retains sufficient permeability to be dolomitised, while their muddier surrounds are not (e.g. Red River Dolomite of North Dakota). Whatever the setting, the rule of thumb is that refluxing brines will preferentially dolomitise whatever carbonate facies is capable of acting as an aquifer at the time of reflux. The economic significance of reflux dolomite was first noted in the 1960s in the various evaporite-associated Permian dolomite reservoirs of West Texas (Adams and Rhodes, 1960). Reflux dolomitisation also controls porosity/permeability distribution in the finer-grained parts of some Jurassic Arab Formation reservoirs in Saudi Arabia, as well as the Permian Khuff Formation in the Arabian Gulf, the Smackover Formation carbonates of the Gulf of Mexico, the Upper Permian Changxing Formation and the Lower Triassic Feixianguan Formation, NE Sichuan Basin, China, and many other oil and gas fields across the globe where dolomites occur beneath an evaporite seal (Sun, 1995; Warren, 2000a; Jiang et al., 2013). 

Yet, in other depositionally similar evaporitic settings, some of the mesohaline laminites that underlie bedded salts are not dolomitised, typically because they were evaporite-cemented in the strandzone before the onset of reflux flushing. They were too tight to transmit the volumes of Mg-rich brine needed for dolomitisation. Likewise, dolomites immediately below a saltern or mudflat brine source tend to be overdolomitised and evaporite-plugged, there the aquifer limestones were located in the zone of most intense flushing by salt-supersaturated brines (Figure 10.9). Syndepositional permeability, in units deposited immediately after a transition into widespread evaporite deposition and the condition of subsalt aquifers, controls the type and extent of the brine reflux alteration halo. So, porosity evolution in subsalt sediments can vary widely, according to the ambient hydrology.

Worldwide, Phanerozoic dolomite reservoirs are defined by four syndepositional associations (Sun, 1995; Warren, 2000a): (1) evaporitic mudflats in a carbonate platform, most often a ramp profile (roughly equivalent to peritidal-dominated carbonate of Sun, 1995), (2) saltern-sealed platform carbonates with mudflat development over palaeotopographic highs - this system typically develops across an epeiric platform behind a rimmed shoal profile (roughly equivalent to subtidal carbonate associated with evaporitic tidal flat/lagoon of Sun, 1995), (3) basinwide evaporite seal (subtidal carbonate associated with basinal evaporites of Sun, 1995), and (4) nonevaporitic carbonate sequences associated with topographic highs/unconformities: platform-margin buildups or burial related fault/fracture controls. Three of the four worldwide dolomite-hydrocarbon associations show an intimate association with evaporites. Brine reflux is the dominant process in dolomite creation in all three, although later burial dolomites can overprint it. The process of mixing-zone dolomitization, typically considered part of process set (4), has received enough criticism in recent years to suggest that it no longer be considered viable for making large amounts of dolomite. In its place Li et al. (2013) propose a somewhat more specific model, which still requires fluid mixing whereby an ascending flow of freshwater mixes with evaporated seawater about the edge of a saline basin, leading to extensive dolomitization.

Model of reservoir creation via saltern brine reflux, based on dolomite distribution in the Upper Permian Changxing Formation (P3ch) and the Lower Triassic Feixianguan Formation (T1f), NE Sichuan Basin, China (after Jiang et al., 2013).

Dolomite reservoirs created by brine reflux can be subdivided using the dominant depositional style of the evaporite capstone, namely, platform and basinwide (Figure 5.9). In platform-evaporite-sealed dolomite associations, the evaporite seal is typically ≈ 5 -10 metres thick (although it can be 20-30m thick) and is usually dominated by saltern or mudflat anhydrite interlayered with shoaling platform carbonates. This evaporite cap can be further subdivided into evaporitic mudflat or saltern-dominated. Basinwide seals to carbonate reservoirs tend to be thick (>100m), halite-prone in the basin centre and to cap carbonate buildups about the basin edge. Such buildups typically grew before the saline giant stage. Ongoing or longterm regional reflux beneath accumulating evaporites in both platform and basin settings can “overdolomitise” the reservoir and encourage evaporite plugging leading to occlusion of effective porosity (Warren, 2000a for a summary). In platform settings, such porosity-depleted overdolomitised zones tend to be most common in regions of restricted carbonate deposition beneath leaky evaporitic mudflats (these are the typical caps to Sun’s peritidal association). These sediments tend to accumulate in the more updip evaporite-dominated portions of a carbonate platform, where underlying carbonates have been flushed for extended periods by hypersaline brines. With basinwide-sealed associations, a later burial overprint and pervasive intra-reservoir karst/fracturing event seem to be needed to create and maintain economic porosity levels.

A comprehensive discussion of the world’s major oil and gas fields with bedded evaporite seals, and all the relevant references, can be accessed in Warren, 2016)

Evaporites and reservoir quality (Warren, 2016 for detail)

Without exception, the largest of the various oil and gas fields sealed by bedded evaporites are subsalt and mostly hosted in partially dolomitised marine platform carbonates (Warren, 2016, Chapter 10). In most giant and supergiant fields, the evaporites not only hold back the hydrocarbon column but also help create and maintain reservoir quality (Table). The most impressive examples are the various Arab D reservoirs in the Middle East, with slightly smaller but still very significant accumulations in oil pools in San Andres Formation of West Texas and reservoirs in the Sichuan Basin of China. In all these examples the depositional porosity of the reservoir has been altered and variably enhanced by brine-related allochem leaching and early reflux-driven dolomitisation. The degree of meteoric overprint at this early burial stage of diagenesis is minor to nonexistent.

Syndepositional edge-of-evaporite dissolution from seawater freshening can occur, and it leads to substantial thickening of high quality groundwater-controlled eolian depopods, as in the billion-barrel North Ward-Estes Field. Deeply circulating regional meteoric influx driven by a lateral groundwater head, mixing with brines of the reflux plume, can also create or alter poroperm distributions below evaporite seals and so influence reservoir quality, as in the Smackover Formation reservoirs of the Gulf of Mexico. In my experience, most variation in subevaporite reservoir quality is the end product of a combination of depositional facies and varying intensities of evaporite plugging, dissolution, reflux dolomitisation and burial stage cementation.

Lateral and vertical variations in all but the latter are typically indicated by facies variations in the seal itself. Yet, for much of the oil industry, evaporite plugging and reflux dolomitisation are associations that geological and geophysical staff do not quantitatively integrate into a reservoir model (other than via loosely controlled geostatistical formulations). The relevance of a bedded evaporite at any scale, beyond the consideration of its seal integrity in exploration or field development, is not part of most reservoir evaluation studies (The typical question to be asked and answered of the evaporite seal in a petroleum system is; Is it thick enough? Usual magic numbers worldwide for answering yes are; greater than 10 metres thick for a clean anhydrite seal, and greater than 5-10 metres thick for halite). Once the integrity of an evaporite seal or cap to a potential reservoir is considered established, further study of the seal properties or intraseal textures is not regarded as relevant, other than hoping for, or establishing, its lateral persistence. Instead, subsequent research and measurement focus on the properties of the reservoir itself, the seal is rarely cored and, if it is, this is usually the result of an error in picking depth to top reservoir. 

Identification and prediction of features associated with bedded evaporites that are useful in helping define distribution of subsalt or salt adjacent reservoirs (from Warren, 2016).

Attempting to better understand diagenetic intensity in the reservoir using signatures from wireline tool measurements taken across the seal intersection is typically considered too complicated, or the possibility is not even recognized. Yet, as any carbonate geologist will testify, diagenesis is what distinguishes properties in any carbonate reservoir from those in a sandstone. Pervasive, but variable, diagenetic intensity is what controls carbonate reservoir quality in every bedded evaporite-sealed petroleum system worldwide. Almost all of the matrix quality in the world’s giant and supergiant bedded evaporite-sealed carbonate fields was established during deposition and early burial. This is when surface topography controls intensity of circulation in the diagenetic hydrology (Table). Resultant poroperm plumbing can be locally enhanced by later fracture development and perhaps the formation of coarsely crystalline saddle dolomites (typically fed by fractures and faults). In petroleum systems exemplified by the examples of Yates and North Ward-Estes fields, reservoir quality is predictably tied to the style and position of the early evaporite hydrology and is indicated by evaporite textures in the seal (Figure).

Summary of the various ancient platform and basinwide bedded evaporite settings where a combination of evaporite sealing, dolomitisation (both early and lake) and focused evaporite related fluid flow create a variety of hydrocarbon traps (From Warren, 2016).

The same approach is also useful in other reflux-dominated carbonate reservoirs, as in the Arab and Khuff formations in the Middle East. The oil industry does much more reliable seal prediction and modelling (both seismic and reservoir scale study) in sandstone-shale associations than in carbonate-evaporite systems. Our understanding of reservoir problems in a carbonate reservoir is more often post-mortem than predictive. More reliable maps of anhydrite plugging at the reservoir level and flow unit correlations for waterfloods in carbonates are sorely needed. In bedded evaporite-sealed systems this requires the integration of field-scale maps of seal facies with maps of reservoir properties in intervals below the seal. Most oil companies do not currently do this. Worldwide, the focus of the mapping of lateral and vertical rock property variation is focused on the reservoir itself, and it is seldom related to variation in seal facies.

Yet wireline property variation in the evaporite seal is easily done. There is no complication of the wireline signature by porosity or fluid variation. That is, evaporite seals are tight, they lack porosity and fluid content, so what is seen in a wireline signature in an evaporite seal intersection is directly related to style and purity of the evaporite and these properties are directly relatable to deposition style. The first step is the construction of a map of the facies mosaic preserved in the seal, using wireline-based core-calibrated image and conventional logs. At the local scale, such a map uses separation of sabkha from salina signatures. At the broader scale, it uses wireline-based separations of evaporitic mudflat from a saltern. Next, a field-wide map of reservoir quality is constructed, or existing maps of quality can be checked by recalibration to existing core and wireline/image data (in a producing field this data is available at varying degrees of reliability). The field-wide facies mosaic map derived from the seal is then overlain on the field-wide map of reservoir quality and production data. A match or mismatch of the two outputs tests whether the early burial hydrology and associated palaeotopography have controlled much of the reservoir leaching/dolomitisation and anhydrite plugging.

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