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Stabler Colin, 2016. "Triple-Porosity Diagram Proposed to Characterize Complex Carbonate Reservoirs—Examples from Mexico", Mesozoic of the Gulf Rim and Beyond: New Progress in Science and Exploration of the Gulf of Mexico Basin, Christopher M. Lowery, John W. Snedden, Norman C. Rosen
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Limestone and dolomite reservoir rocks are by far the more important producers of oil and gas in Mexico compared to sandstone reservoirs. Many of the carbonate reservoirs are complex in that they display three types of pores: matrix porosity; vugs, and cavernous porosity; and fracture-induced porosity. This combination of three types of porosity can be described as “triple porosity.” Each pore type presents a different pore-throat size range and each has a different effect on permeability.
Attempts have been made in the past to characterize “dual porosity” systems. Nelson (1992) illustrated the effect on permeability of the varying predominance of fracture-induced pores verses matrix pores. On the other hand, Del Angel et al., (2013) compared the effect of varying amounts of fractures and vugs for carbonate breccias in Mexico. The presently proposed ternary diagram (Fig. 1) combines the two previous approaches by comparing the relative abundance of matrix porosity, fracture-induced porosity, and pores due to vugs and caverns. Thus reservoirs with only fractures, (Nelson Type I), will plot at one of the apices; they may have minor matrix porosity, (Nelson Type II), and/or a few vugs. Reservoirs having matrix porosity, (Nelson Type IV) will plot at another apex; they may have a few fractures (Nelson Type III), and/or minor amounts of vugs.
Rocks having only vugs and caverns will plot at the vug/cavern apex; they will be effective, permeable reservoirs if they have significant fractures, (Del Angel type IFD 1 and IFD 2) or they may have significant matrix porosity to connect the vugs, in which case they will plot along the base of the ternary diagram.
Examples in Mexico
Carbonate reservoirs in Mexico show a varying mixture of these three end-member pore types depending on their original depositional facies, Figure 1, and later diagenetic overprint. They may have predominantly only one pore type; they may have dual porosity, or as in many examples, have triple porosity.
The most common reservoirs having mainly matrix porosity are oolitic and bioclastic grainstones. Their matrix porosity is a result of various diagenetic processes, including incomplete cementation of pores between the grains, “inter-granular” porosity (Fig. 2A), and alteration of the grains to produce pores between the crystals that make up the grains (“intra-granular” porosity, Fig. 2B). These grainstones often contain a few vugs caused by dissolution of calcareous fossils (Fig. 2C). When the grainstones are dolomitized, the grains are frequently dissolved (Fig. 2D). Fracturing enhances the permeability of the dolomitized grain-stones.
Reservoirs which contain a predominance of vugs and caverns are made up of rudistid and coral boundstone. They contain original pores preserved in rudistid shells and vugs caused by dissolution of rudistid, coral (Fig. 3A) and other calcareous fossils. The caverns are a result of karstic processes. These vugs and caverns are interconnected by zones of matrix porosity.
Reservoirs having mainly fracture porosity were deposited as lime mudstones, often dolomitized in some regions. In this reservoir facies, matrix porosity is low but can be effective because of interconnecting fractures (Fig. 3B).
The most important reservoir facies in Mexico is carbonate breccia, which is common in a number of fields and was deposited at various times during the late Mesozoic to Paleogene. In this breccia, which is commonly dolomitized, each of the three pore types is present in variable amounts (Fig. 3C), resulting in this reservoir facies being very heterogeneous on a small to large scale. Because reservoir permeability depends on the different types of pores, permeability is also very variable. It has thus been difficult to predict how the carbonate breccias will produce once they are discovered in a well. Prediction of important parameters such as initial flow and decline rates, as well as estimates of field reserves that can be recovered, have been erroneous, sometimes underestimated.
Semiquantification of Pore Types by Wireline Logs
With close cooperation between geologists and petrophysicists, the relative amounts of porosity in the matrix pores, vugs, and fractures can be estimated from well data and suites of wireline logs.
Porosity in the matrix can be determined from sonic logs and resistivity logs given a cementation exponential calibrated from core plugs. Permeability measurements from cores plugs establish a relationship with porosity for each particular reservoir lithology.
Porosity in fractures
Fractures can be identified by lost circulation zones as well as in cores, on caliper logs, and on borehole image logs. The amount of fracture porosity can be determined from the difference between neutron/density porosity and sonic porosity. The effective permeability of such fractures can be deduced from pressure build-up tests and production decline curves.
Porosity in vugs and caverns
Vugs and caverns can be identified by lost circulation zones and in cores, on caliper logs and on borehole image logs. The neutron magnetic resonance log will give a value of the porosity due to large pores, (vugs), verses small pores (matrix and fractures). An indication of the permeability associated with these porosity types can also be deduced.
Thus the position of a particular reservoir on the pore-type ternary diagram can be plotted. A hypothetical example is shown on Figure 4: the reservoir interval has 12% total porosity, sonic porosity (matrix) of 6%, vuggy porosity of 4% and fracture porosity of 2%.
Variation within the reservoir from bed to bed, or zone to zone, or area to area, can thus be depicted quantitatively on the ternary pore-type diagram. This information will be invaluable to the reservoir engineer for building static reservoir models.
This paper proposes a method to characterize complex carbonates whereby the relative abundance of matrix porosity, fracture-induced porosity, and porosity in vugs and caverns is plotted on a triple-porosity poretype ternary diagram. This method will aid the reservoir engineer in determining and modeling the dynamic characteristics of the various combinations of porosity and permeability types. It is hoped that this approach will help in improving the assessment of complex carbonate reservoirs in Mexico and elsewhere in the world.
I wish to thank Pemex Exploration management for permission to include illustrations from my reports to Pemex between 1969 and 1970. Bernardo Martell generously offered his petrophysical advice. Finally I wish to thank all the Pemex geologists who worked with me on these carbonate reservoirs many years ago.