DIAGENESIS

Sandstone Burial

Most modern sands are deposited with porosities of somewhere between 40 and 50 percent. In general, this porosity is lost with increasing depth of burial.

Sandstones lose porosity with burial at various rates according to several factors. Figure   1 illustrates the effect of mineralogy.

Figure 1

Figure 1

Chemically unstable volcanic sands of Japan lose porosity very quickly with burial. At depths of 2 to 3 kilometers porosity is less than 10 percent. For the feldspar-rich arkosic sands of the North Sea, porosity can survive to somewhat greater depths. For the chemically stable pure quartz sands of the Niger delta, porosity can be preserved to depths of 4 to 5 kilometers. Therefore, the chemical composition of a sand is one of the controlling factors on its overall rate of porosity loss. Dodge and Loucks (1979) present data to show how the more mineralogically stable sands of the Texas Gulf Coast are better able to retain their porosity with depth.

The geothermal gradient also affects the rate of the chemical reactions that cause porosity destruction. In general, the higher the geothermal gradient, the greater the rate of porosity reduction with depth (Galloway, 1974). Figure   2 shows porosity: depth relationships for sandstones associated with two different temperature gradients in northeast Pacific basins.

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Figure 2

Figure 2

It indicates a greater rate of porosity reduction associated with the higher temperature gradient.

Overpressure can help to preserve porosity at great depths (Plumley, 1980). Figure   3 is a graph of porosity versus depth in a well in the United States Gulf Coast; it shows preservation of porosities below the top of the super-normal pressure zone.

Figure 3

Figure 3

The presence of hydrocarbons also preserves porosity (Fuchtbauer, 1967). Once oil or gas invade a reservoir, connate waters are prevented from moving through it with the chemicals which can precipitate as cements, destroying the porosity. Even after hydrocarbon invasion, however, porosity may still be diminished by compaction.

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Cementation

Figure   4 is a sketch of a thin section of a sandstone reservoir rock from the Brent field in the North Sea.

Figure 1

Figure 4

The angular shape of many of the grain boundaries is due to silica cement that has grown over them in continuity with the original grain. It is the crystal faces of the secondary cement which give the pore spaces their angular boundaries. Many sandstone reservoirs have lost some of their porosity by secondary silica cementation of this type. Many other types of cement are found in sandstone reservoirs, especially calcite and the clay minerals.

Figure   5 is a sketch of a thin section of a sandstone showing porosity having been totally destroyed by a cement of large calcite crystals.

Figure 2

Figure 5

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A third important type of cement in sandstone reservoirs is provided by the authigenic clay minerals. There are several types of clay. Two particularly important ones are kaolin and illite. Figure   5 is a sketch of a sandstone with interstitial kaolin crystals.

Figure 3

Figure 5

These generally occur with a chunky euhedral habit. As you can see, these kaolin crystals occupy pore space, but they do not significantly affect the permeability of the rock. Figure   6 is a sketch of a sandstone with illite in the pore spaces.

Figure 4

Figure 6

Authigenic illite generally occurs as long thin angular crystals which radiate from the quartz grains on which they grow. Thus, a small amount of illite may affect the

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permeability to a very large extent by bridging over and blocking the throat passages between the pores.

Figure   7 is a graph on which porosity is plotted against permeability on a logarithmic scale, showing the porosity: permeability distributions for illite-cemented sands and kaolin-cemented sands from some North Sea gas fields.

Figure 5

Figure 7

It should be noted that the porosity is mostly between 5 to 25 percent, irrespective of the type of clay, but the permeabilities for kaolin-cemented sands are far higher than the permeabilities of the illite-cemented sands.

Secondary Porosity Development

Figure   8 is a sketch of a thin section of a sandstone.

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Figure 1

Figure 8

Notice there are several very large pore spaces, so large that it is improbable they were formed when the sediment was originally deposited. These are secondary solution pores where a grain has dissolved and the porosity has been increased.

Secondary porosity generally involves the leaching of carbonate cements and grains, including calcite, dolomite, siderite and shell debris. It also involves the leaching of unstable detrital minerals, particularly feldspar. In this latter case, leached porosity is generally associated with kaolin cementation, both replacing feldspar and occurring as an authigenic cement in its own right.

The predominance of kaolin and the fact that carbonate has been leached out suggest that the leaching was caused by acidic solutions moving through the rock. The source of these solutions is still a matter for debate.

Many examples of secondary porosity occur beneath unconformities. It is likely that in these cases, meteoric water causes weathering of sandstone inducing secondary porosity. These sands are then buried beneath onlapping sediments above the unconformity.

Secondary leached porosity in sandstones is also reported to be common at all depths, from the near surface to the deep surface in Lower Tertiary sandstones of the Texas Gulf Coast (Loucks et al, 1979).

Summary: Diagenetic Pathways

Figure   9 shows the diagenetic pathways of sandstone.

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Figure 1

Figure 9

Sands are deposited with porosity of some 40 to 50 percent (a). As these sands encounter shallow burial, their porosity diminishes by compaction and cementation to some 20 to 30 percent (b). Deep burial can lead to a total obliteration of porosity by extensive cementation and compaction (c). Deeper burial may eventually lead to metamorphism. At any point during burial, either deep or shallow, secondary porosity may be induced by leaching (d). Good reservoir rocks may therefore be found at depths at which one might expect most primary porosity to have been destroyed by compaction and cementation. The best event that can possibly happen to a sand is for oil or gas to invade pore spaces (e). Once this happens, cementation is inhibited and any further porosity loss is minimal, caused only by compaction.

Effects of Diagenesis on Carbonate Reservoirs

Porosity in sandstone reservoirs is most typically intergranular and primary. Carbonates generally have secondary porosity which reflects a far more complicated diagenetic history. Detailed accounts of carbonate diagenesis may be found in major texts published by Bathurst (1975), Wilson (1975) and Chilingar et al (1972), as well as in papers by Purser (1978) and Longman (1980).

Aragonite is the type of calcium carbonate (CaCO3) which occurs in most recent sands and muds. It is unstable in the subsurface, however, so that one of the first diagenetic changes of a lime sand is the alteration of aragonite to calcite. This can cause extensive modification of the porosity. The original skeletal grains are leached out and a rim cement grows around the original grain boundaries.

The second major carbonate mineral is dolomite [CaMg(CO3)2], a mixture of calcium and magnesium carbonate.

Limestones

Like terrigenous sands, lime sands and skeletal carbonates have initial porosities of 45 to 50 percent, but in most ancient limestones that porosity has been almost

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totally destroyed. We shall now take a close look at diagenetic pathways for carbonates.

Figure   10 shows the various routes that may be taken by a skeletal lime sand as it is buried and undergoes diagenesis.

Figure 1

Figure 10

At time of deposition initial porosities are as high as 50 percent (a). If burial takes place very quickly without early diagenesis, porosity may be reduced, largely by compaction as the shells and grains are squashed (b). Residual porosity may then be in filled by a sparite cement (c). In some environments early diagenesis takes place with a rim cement of sparry calcite crystals (d), sometimes accompanied by solution of the original cells or grains giving rise to bimoldic porosity (e). If hydrocarbons invade the reservoir, further porosity loss by cementation is prevented and the rim cement gives the rock sufficient resistance to compaction (f). At any time in its history, even if all porosity has been destroyed by compaction and cementation, secondary solution porosity can form (g). This can be either fabric-selective moldic porosity or vuggy porosity, which cross-cuts the original grains and fabric of the rock. This later secondary porosity can also be invaded by hydrocarbons preventing any further cementation of the secondary pores (h). If petroleum invasion does not occur, the secondary pores may be infilled with a sparry calcite cement (i). Thus, it can be seen that the diagenetic pathways of carbonates are extremely complex and that carbonate reservoirs are very difficult to develop. Porosity distribution may be unrelated to the original depositional facies.

Figure   11 illustrates two types of secondary solution pores: moldic and vuggy, as shown in the previous diagram.

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Figure 2

Figure 11

Dolomites

Primary dolomites are those which form contemporaneously with associated sediments, generally limestones and often evaporites. They are commonly found in salt-marsh sabkha sequences and are typically bedded, cryptocrystalline, chalky and floury. Petrophysically, they are like chalks or shales in that they are often porous, but lack significant permeability because of their fine grain size.

Secondary dolomites, on the other hand, are those which form by "dolomitization", the replacement of a pre-existing calcium carbonate deposit. They are often coarsely crystalline and, as seen earlier, have intercrystalline porosity that may exceed 30%.

When dolomite replaces calcite, there is a bulk reduction of the original rock volume by as much as 13 percent. Whether the observed intercrystalline porosity is related to this volume reduction is a matter of debate.

Figure 12 is a sketch of a thin section of a secondary dolomite, showing that the intercrystalline pores are large and often interconnected.

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Figure 1

Figure 12

Because of this, they are not only porous but also permeable, and thus they can make excellent hydrocarbon reservoirs. In fact, approximately 80% of North American carbonate reservoirs are dolomite (Zenger et al, 1980).

Important examples are:

the Jay field in Florida with over 340 million barrels of recoverable oil reserves, mostly from leached dolomites of the Jurassic age Smackover formation (Ottmann et al, 1976);

Silurian-Devonian age Hunton gas reservoirs of the Anadarko Basin (Harvey, 1972); and

the huge Panhandle-Hugoton field of Texas-Oklahoma-Kansas in which Permian age Wolfcamp dolomites yield a significant portion of the estimated 70 trillion cu. ft. of gas and one billion plus barrels of oil (Pippin, 1970).

A variety of dolomite types exist in nature and are the subject of continuing discussion. For a review of the dolomite "problem" and for papers representing diverse opinions regarding the formation of dolomite, the reader is referred to Zenger et al (1980).

Atypical Reservoirs

About 90 percent of the world's discovered petroleum occurs in sandstone and carbonate reservoirs in about equal proportions. The remaining reserves occur in what can best be described as atypical reservoirs. Almost any rock can serve as a reservoir, providing that it has the two properties of porosity and permeability. Atypical reservoirs include shales, granites and other igneous and metamorphic rocks. Generally, porosity that occurs in these is due to fracturing.

An atypical reservoir is shown in Figure 13 , a cross-section through the Augila field of Libya (Williams, 1972).

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Figure 1

Figure 13

This field consists of an old basement high of weathered granite with onlapping sands and reefal carbonates.

Production comes from the carbonates and sands, as well as the granite. One well, the #1 well on the cross-section, penetrated through the cap rock of the field into granite without penetrating either reefal or sand reservoir. This well flowed at over 40,000 barrels of oil per day from the granite. The porosity was a mixture of fracturing and solution, where chemically-unstable feldspar grains were leached out to leave granite washes largely made up of residual quartz grains. Reservoirs such as this are rare, however. Other important examples of fractured reservoirs are:

the fractured Franciscan (Jurassic) schist fields of southern California (Truex, 1972);

the Spraberry field of Texas with reserves of one billion barrels in fractured shale, siltstone and fine sandstone (Wilkinson, 1953);

LaPaz and Mara fields of Venezuela (Miller et al, 1958); and

the Asamari limestone fields in Iran (Hull and Warman, 1970).

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