Shale Plays Need Seals Too

In an earlier post, I argued that there may be significant lateral migration within shale reservoirs that can lead to higher maturity fluids produced from lower maturity areas, and even occasionally dry gas production in the oil window. In this post, I would like to propose that shale reservoirs also need seals to work. 

Sedimentary rocks have a wide range of pore sizes. In a conventional reservoir, HC saturation builds up due to higher capillary pressure caused by the buoyancy of the column (Schowalter, 1979). Saturation is highest at the crest of the reservoir. 

In a shale reservoir, there may not be an effective column. The increase in saturation and capillary pressure is caused by generation of hydrocarbons. However, it will also require the presence of tight rock facies (above, below and laterally) to prevent migration out of the shale due to the increased capillary pressure. From MICP studies on shales, we see that shales have a wide range of displacement pressures (Pd), from 200 psi to >10,000 psi. The typical tight facies may have a Pd of ~6,000 psi mercury-air (~320 psi oil-water). After saturating the adsorptive kerogen, the generated HC fluid begins to fill the zones with larger pores (the reservoirs with low Pd) first. As saturation in the reservoirs builds up due to continued generation, capillary pressure increases, as hydrocarbons invade progressively smaller pores. Saturation may reach >50% when the capillary pressure exceeds the Pd of the seal and migration out of the shale begins. Obviously, without the sealing facies, a homogeneous rock cannot retain high saturation.

HC wet or partially HC wet pores may initially build up saturation without increasing capillary pressure.

 

From the above reasoning, higher Pd for the seals inter-bedded with the more porous zones at various scales ( millimeters, inches, to feet ) leads to higher saturation in reservoir intervals. Some shale plays may not work due to the lack of seals rather than the lack of porosity. Most studies on shale plays to date have focused on the porosity of the reservoirs, which ranges between 5 and 15% typically. If you agree with the above argument, perhaps it is also important to look at the seals (with less than 5% porosity) inter-bedded with, above and below the reservoir zones. 

Zhiyong He, ZetaWare, Inc.

Dry Gas, Wet Gas, Condensate and Condensables

At a recent industry conference a poster summarised aspects of the petroleum systems in a particular basin. The authors noted that some reservoirs contained "dry gas" while others contained "wet gas". The boundary between the two was not defined but it was clear from the context that the distinction reflected the condensate content: gases having more than about 20 bbls/MMscf  of condensate were classified as "wet".

Wet vs. dry gas definitions and terminology can be confusing so I thought it might be worth posting a summary here. Firstly, let's look at the composition of a typical gas condensate:

This one is from the textbook on the phase behaviour of reservoir fluids by Pedersen and Christensen (2007). We can define four groups of compounds: Methane (C1) being the only member of the first group then ethane (C2), propane (C3) and the butanes (normal and iso) making up the remaining "permanent" gases, the "condensate" range with compounds having from 5 to 14 carbon atoms and the "oil" range consisting of compounds with 15 or more carbon atoms. The "condensate" and "oil" ranges are labelled that way because fluids with most of their liquid mass in those carbon number ranges tend to be gas-condensates and oils in the sub-surface respectively. The "permanent" gases are in the gas state at standard surface conditions of 1 atm pressure and 15 C (60 F)

The ideal condensate-gas ratio or "CGR" of a fluid is the ratio of the liquids to the gas species, usually expressed as their respective volumes under standard surface conditions. In the US, "oil field" units are used so that CGR is barrels of condensate per million standard cubic feet of gas (bbls/MMscf). In Europe the units are more commonly cubic metre gas per cubic metre liquids (M3/M3).

When speaking of wet vs. dry gas in the conventional E and P realm, mostly we are referring to the CGR. What is a "significant" CGR depends on the context, particularly the value it may add to a gas development. For example, for an LNG development based on a 5 trillion cubic feet (TCF) resource, a CGR of 10 bbls/MMscf would yield 50 million barrels of condensate (in ideal circumstances).

There are few standard definitions in the literature but (a) the state of New Mexico defines a "gas" well as one producing a fluid with less than 10 bbls/MMscf of liquids  (see http://164.64.110.239/nmac/parts/title19/19.015.0002.htm. item G6) and (b) the Encylcopedia Brittanica on-line defines a wet gas as anything containing more than 2.5 bbls/MMscf.

The standard reservoir engineering definition of a "dry gas" is one that yields ZERO liquids at surface temperature and pressure. On the phase (P vs T) diagram for such a gas, the isotherm of surface temperature does not intersect the phase curve at any point. Another way of saying this is that the cricondotherm for this fluid is lower than surface temperature. The corresponding definition of a "wet gas" is one that will yield some liquids at surface temperature and pressure but there is no pressure at which liquids will begin to condense at reservoir temperature. For a wet gas, the cricondotherm lies somewhere between the surface and reservoir temperature. A gas-condensate is a fluid for which a reduction in pressure at reservoir temperature will, at some point between initial reservoir and surface pressure, cause liquids to drop out.

In the realm of unconventionals, a somewhat different terminology - one used by the natural gas industry -  is prevalent. Gas wetness refers to the content of C2+, i.e. everything except methane is the "wet" stuff. These are called the "natural gas liquids" or "NGL" even though ethane through to the butanes (C2 - C4) are not liquids under standard surface conditions. The condensate fraction (C5+) is a sub-fraction of the NGL and, just to be extra confusing, the NGL are also called the "condensables". This comes about because during natural gas processing methane - the ultimate "dry gas" -  is separated from all other compounds by either cryogenic cooling or by absorption. The condensate fraction of the condensables (the C5+ bit remember !) can also be called "plant condensate" or "natural gasoline". Just for completeness, let me add that the "liquefied petroleum gas (LPG)" that we use in our barbequeue, car or for cooking at the vacation house is propane, butane or a mixture of the two.

Confused yet ? Now enter the geochemists: Gas wetness to a geochemist is defined as the molar ratio or percentage of the "wet" gases to the total of C1 to C5 gases with no consideration of the condensate species at all. . Errr...except that the pentanes - liquids in a cool room but gas in a hot room (37 C/97 F) -  are generally included. Thus, we calculate the wetness of mud gas (gas while drilling) as the sum of C2-C5/ the sum of C1-C5 and express it as a percentage.

The wetness of a gas (geochemical definition) and condensate-gas ratio are clearly related. However, the relationship is specific to a particular petroleum system and also to processes which may have altered the fluid during movement from source to trap and/or in the reservoir. The figure below shows how gas wetness relates to CGR for several different gas-condensate fields, each hosting stacked accumulations. It is obvious that the gases in field 3 have a very different character to those in the other fields. In particular there is almost no change in gas wetness for fluids varying in CGR from ~ 30 to ~ 75 bbls/MMscf. This implies a decoupling of the gas and liquid fractions of the charge with, for example, a fixed amount of liquids being diluted to variable extent by a near fixed composition gas. This in turn might imply different source kitchens and migration routes or some migration fractionation process.

Finally, it is worth noting that the phase behaviour of a gas-condensate system also depends on the composition of the gas and liquids fractions. The figure below shows gas chromatograms for several condensates with different compositions and corresponding to fluids with different CGRs (nb: no chromatogram is available for fluid "F")

Note that condensate E is slightly contaminated with an olefin based synthetic drilling mud.

The pressure at which a gas condensate begins to separate into oil and gas in the subsurface is called the "dew point" or "saturation pressure (Psat)". This pressure is a function of the CGR but also of the mutual miscibility of the liquid and gas components. The most important factor is the composition of the liquids (condensate). If they are very light, they will more easily enter the vapour phase so that we have a higher CGR for a given dew point. Conversely, the heavier the liquids, the lower will be the CGR for the same saturation pressure. The dew point pressure vs. CGR data for the condensates A - G above are shown in this figure (along with some data from the UK North Sea petroleum system and a published emprical correlation for the same area. (nB; gas-liquid ratio - GLR - is displayed - CGR = 1/GLR *1,000,000)

Note the wide variation related to condensate composition. In particular, note that the very light condensates B and C (yellow dots) show low dew point pressures even though they have a high CGR (~ 95 bbls/MMscf, or GLR ~ 10,000). This reflects the high mutual miscibility of the liquids and gases for these fluids. It is often assumed that finding a high CGR gas in a shallow reservoir increases the likelihood of a finding oil in the system. In fact, the reverse is true: If the liquids are light enough to remain in the vapour phase even in high concentration, there are few oil range molecules present. Condensates of type "G" (43 bbls/MMscf) are much more likely to be found in association with oil.