Toward the Study of the Reservoir Properties of Devonian Rocks of the South Minusinsk Basin

S. I. Shishigin

(Presented by the scientific seminar of the Department of Combustible Minerals)

The South Minusinsk Basin, being an ancient intermontane trough, has long been studied from the standpoint of searching within it for oil-and-gas-promising areas. The deep exploratory drilling carried out in the last decade has not yet led to the discovery of commercial accumulations of oil and gas. As a result, further exploratory drilling for oil and gas here is being curtailed.

What, then, is the reason for the failure of petroleum exploration drilling in the South Minusinsk Basin? In our view, two main reasons that led to the unsuccessful results should be singled out. First, the absence of a clear conception of the nature and character of possible traps. Shortcomings in the methods and techniques of opening up and testing potentially productive horizons may be attributed to the second reason, which to some extent is conditioned by the first.

In this note an attempt is made to reconsider certain questions concerning the first reason for the failures. The question may arise whether there is any need to return to this area, where exploratory work has practically been curtailed. In our view, there certainly is. There is no need here to cite examples from the history of the development of the oil industry, when certain oil-and-gas-bearing regions were discovered only after repeated returns to them.

In this connection we decided to analyze the reservoir properties of the Devonian rocks of this promising region, to which the possibility of returning in time is not excluded.

On the Characteristics of the Porosity of Devonian Sandstones and Siltstones

Let us consider the results of analyses of the open porosity of sandy-silty rocks from the Abakan Formation through the Tubin Formation inclusive. In all, 1434 samples were analyzed [1].

The determinations are distributed through the section as follows (Table 1).

The coefficient of open porosity of the sandy-silty rocks of the uppermost Tubin Formation ranges from 1 to 17%, on average from 2 to 6%. The rocks of the remaining part of the section, from the Kokhai Formation through the Abakan Formation inclusive, have porosity from 0.15 to 9–11%, predominantly in the interval 2–4%.

More complete data have been summarized in a graph (Fig. 1), from which it is evident that the predominant porosity values, except in the Tubinskaya Formation, vary within a rather narrow range (2–4%), which remains surprisingly constant with depth.

Table 1

Low porosity indicates a high degree of compaction of all Devonian sandy-clayey deposits, except for the Tubinskaya Formation in the weathering zone.

The graph shown in Fig. 2 illustrates the percentage ratio of samples with porosity of 0–4% to the total number of samples. The graph shows that samples with porosity of 0–4% account for 75 to 83% of the total number of samples, except in the Tubinskaya Formation, in which 60% of the samples have porosity below 6%.

Thus, only \(1/4\)—\(1/6\) of the section samples from the Abakanskaya Formation through the Kokhaiskaya Formation inclusive have porosity above 4%.

Fig. 1. Schematic composite section of open porosity (in percent) of sandy-siltstone Devonian rocks of the South Minusinsk Basin.
1 — minimum value; 2 — maximum value; 3 — interval of mean values. Compiled by S. I. Shishigin.

Fig. 2. Percentage ratio of samples of sandy-siltstone rocks with porosity of 0–4% (for the Tubinskaya Formation, 0–6%) to the total number of samples in the formation.
1 — based on samples from outcrops; 2 — based on samples from boreholes; 3 — based on all samples (outcrops and boreholes). Compiled by S. I. Shishigin.

It should be noted here that these values refer mainly to siltstones.

In fact, the porosity of siltstones is, as a rule, higher than that of sandstones. This is confirmed by the summary Table 2 given below, in which the values of 216 analyses of cores from boreholes of five structures are generalized.

type: Altai, Bystryanka, Bidzha, West Tagar, and North Tagar.

Table 2

It is evident from the table that the porosity of sandstones is, as a rule, approximately half that of siltstones.

It may be considered established that sandy-silty rocks with porosity up to 3% in monoliths are usually impermeable. This conclusion was drawn as a result of studying rocks of the Skiba Zone of the Carpathians [6]. Devonian rocks of the South Minusinsk Basin having porosity up to 6% were deliberately not analyzed for permeability, as being practically impermeable. And samples with porosity above 6% in all cases had permeability of less than 1 millidarcy. Indeed, the exceptionally great tortuosity of very fine capillary and subcapillary pores (and often dead-end pores as well), characteristic of varieties with porosity up to 6%, causes extremely high resistance to filtration. Consequently, we are forced to acknowledge that all rocks of the section under consideration, in monolithic samples, are practically impermeable.

On the fracturing of rocks

Despite the conclusion just made, practice shows, however, that in the section as a whole there are intervals that are practically permeable to varying degrees. This is indicated by industrial gas inflows in wells, even with a testing method that is not sufficiently effective. The productivity of individual wells is measured in tens and hundreds of thousands of m³/day.

In particular, let us calculate the permeability of the interval (1844–1881), penetrated by well 1 on the Bystryanka area, to which a flow rate of 184,000 m³/day is attributed (although it must be assumed that not the entire interval is productive), on the basis of the flow rate under unsteady-state conditions for radial filtration. For this purpose we shall use the following formula [4]:

\[ K = \frac{ Q \cdot \mu \cdot \ln \dfrac{R_k}{r_c} }{ \pi \cdot h \left(P_k^2 - P_c^2\right) }, \]

where \(K\) is the coefficient of gas permeability, in darcies;

\(Q\) is the flow rate of the gas well, reduced to atmospheric pressure [[unclear: continuation cut off]].

measured in cm³/sec; in this case \(2.13 \cdot 10^6\);

\(\mu\) — gas viscosity in centipoises under formation conditions (at 320°K), equal to 0.023;

\(h\) — interval thickness in cm (3700);

\(R_k\) — average drainage radius in cm (take 150000);

\(r_c\) — well radius in cm (10);

\(P_k\) — reservoir pressure in atm (180);

\(P_c\) — pressure at the well bottom in atm (3).

Substituting these data into the formula and solving, we obtain for \(K\) a value equal to 1.2 millidarcys. The calculated value, being an average, is already considerably greater than the value obtained in laboratory study of the core. This indicates that the permeability of the interval is due to fracture porosity.

In addition, in interpreting this value the following must be taken into account. The value obtained characterizes the permeability of the entire interval (37 m thick) as a whole, consisting of both permeable and impermeable beds. In turn, because of the unequal fracturing among the permeable layers of the interval, there are layers that are more permeable and less permeable. Thus, in the general case, the permeability of a fractured reservoir will be directly proportional to the square of the fracture aperture and to the square of their frequency in the filtration cross section. Individual thinly bedded argillite–siltstone rocks, in which the fracture density is several times greater than in massive sandstones, may possess a permeability hundreds of times greater than that calculated for the entire interval.

And the true permeability of fractures in the rock will be many times greater than the permeability of the fractured rock itself as a whole, in which, in addition to fractures, there are also undrained blocks.

Consequently, it may be concluded that individual fractured horizons of the 1844–1881 m interval in well 1 of the Bystryanskaya area possess moderate to good permeability.

The following indicators, which may be divided into direct and indirect, also point to the fracturing of Devonian rocks of the South Minusinsk Basin.

Direct indicators

1. Numerous calcite and gypsum veinlets.
2. Open fractures recorded in the core.
3. Fractures completely or partly filled with bituminous material.

Indirect indicators

1. High water yield in some beds impermeable in monolith (Severo-Tagarskaya area, 140 m³/day).
2. “Drops” (by 1–2 m) of the tool when passing through certain intervals.
3. Low core recovery (10–15%) or its complete absence in the core barrel.
4. Cases of absorption of drilling mud, for example, in the Altaiskaya area [1].
5. An anomalously high content of secondary mineral formations, which is more or less equally characteristic of all rocks of the Devonian section [3].

One of the factors substantially influencing the development of secondary minerals in rocks is the pressure accompanied by the formation of fractures.

It should also be noted that indirect indicators may point not only to fracturing, but also to cavernosity, especially in carbonate rocks.

It follows from this that the reservoir properties of rocks must be studied not on monolithic core samples in the laboratory, as has been done up to now, but in the bed as a whole, that is, under real conditions. Hence there arises the need for a special study of the fracturing of Devonian rocks from the standpoint of their reservoir properties.

In this connection, in our view, the following problems require solution: a) development of a method for determining the coefficient of fracture void space; b) development of a method for determining the coefficient of fracture permeability; c) study of the origin of fractures; d) study of the distribution of fractures in relation to the structural position of the rocks; e) study of the distribution of fractures in relation to the lithological composition of the rocks; f) study of the quantitative relationship between porosity, fracture void space, and cavernosity of rocks, for example carbonate rocks; g) prediction and identification of fractured zones (areas or intervals) for the purpose of assigning prospecting and exploration work to them.

At present, in studying the fracturing of Devonian rocks, researchers E. M. Smekhov, T. V. Dorofeeva, L. P. Gmid, and others [5] use the processing only of core samples. They determine the fracture void space of a sample in a plane-parallel thin section, assuming that the latter will be numerically equal to the aperture of the fractures cutting the area of the thin section, which they then calculate.

Such a method cannot be considered successful for the following reasons. First, in a thin section it is not possible to detect all the systems of fractures that cut the rock in all three dimensions. For this reason, fracture aperture, all other conditions being equal, will always be less than fracture void space. Second, a characterization of fracturing made by study over a microscopic area can in no way be extended to the entire area, still less to the volume of the rock, since fractures are distributed quite unevenly not only in different dimensions, but even within one dimension. Third, only fractures (even if in one dimension) are taken into account in the recoverable pieces of core, in which open fractures longer than the dimensions of the core are not preserved. Consequently, not only all fractures cutting the core in all three dimensions, but also those in one dimension, cannot be taken into account. Fourth, large bed fractures and cavities cannot be taken into account, since no core at all is recovered from these intervals. And it must be said that both the capacity and the permeability of these large voids cannot be compared either with the capacity or with the permeability of the microscopic closed fissures recorded in the thin section. It is not for nothing that the authors mentioned completely omit from the sphere of study both fractures cutting the bed through its full thickness and cavities. The presence of the latter, however, is indicated by “failures” of the tool and other indirect indicators.

All this, taken together, leads to the conclusion that the values of capacity and permeability of the fractured reservoirs of the Devonian of the South Minusinsk Basin, obtained on the basis of thin-section studies [5], cannot reflect the actual picture. This also explains the contradiction in the studies of E. M. Smekhov and others [5] between the high productivity of wells and the negligible “fracture porosity” (hundredths of a percent). Incidentally, it should be noted that the very term “fracture porosity” for denoting the capacity of a fractured reservoir is highly unfortunate. For this parameter we have proposed the more acceptable term fracture void space.

In the formation of fracture porosity in a fractured reservoir, the principal role belongs to so-called tectonic fractures, that is, fractures of separateness cutting through an individual bed as a whole. These fractures usually develop in all three dimensions. When the coefficient of fracture porosity is taken into account, the initial data are mainly the following parameters: the number of fracture systems, the density (frequency), and the magnitude of their opening in each dimension.

Under equal structural conditions, these parameters depend on the lithological composition, which predetermines the mechanical properties of the rock.

The density of fractures of separateness for one lithological variety, in turn, is directly dependent on the thickness of the bed. It has been established empirically that the thinner the bed, the more frequent the fractures, and vice versa. This rule, inherent in all layered sedimentary deformed rocks, may be regarded as a regularity. Naturally, the same regularity is also characteristic of the rocks of the South Minusinsk basin, which have been folded.

In thin-bedded sandy-clayey (especially dense) rocks, fracturing is developed more intensively than in medium- and thick-bedded ones. If the frequency of fractures in each dimension doubles, then, with the same magnitude of opening, the coefficient of fracture porosity increases eightfold. If the frequency increases threefold, then fracture porosity increases twenty-sevenfold, and so on. Consequently, greater attention should be paid to packets of alternating thin-bedded argillite–siltstone rocks, which at present are almost completely ignored from this point of view.

Fracturing within one and the same rock packet over the area of a structure also develops unevenly; namely, both the density and the magnitude of fracture opening vary. These two parameters are directly dependent on the degree of bending of the beds on the structure. Thus, for example, in sharply expressed anticlinal folds of the South Minusinsk basin, with isotropic fracturing, the magnitude of opening of fractures of separateness will be greater on the crest than on the limbs. And in folds with a gentle crest and steep limbs, the opening of tectonic fractures will be greater on the limbs, especially those intensely complicated by flexures and disjunctive disturbances, which most often develop on steep limbs. Flexures usually pass with depth into disjunctive disturbances. The latter are accompanied by intensified fracturing in comparison with gentle, calm crests. Flexures may also be areas that hinder further migration of fluids along rupture cavities. Consequently, flexural zones may be a kind of trap for fractured accumulations of oil and gas. B. N. Krasilnikov and Ya. G. Kats [2] likewise attach great importance to zones of fracturing in Devonian rocks.

Conclusions

1. In evaluating the permeability of fractured reservoirs, one cannot rely on data obtained from small monolithic samples. To determine permeability under reservoir conditions, one should be guided by geophysical data and by bottom-hole pressure build-up curves. Practice shows that such methods can provide reliable characteristics.

2. The evaluation of the total effective capacity of rocks should be carried out on the basis of data from geophysical investigations (KS, PS, BKZ, etc.). In studying the fracture porosity of rocks penetrated by wells,

it is evidently necessary to use photographic and television installations; to this end, their introduction into mass production must be accelerated and they must be included in the general complex of geophysical investigations carried out on promising horizons.

1. It is also necessary to revise the methodology of prospecting and exploratory work, beginning with the selection of targets for deep prospecting drilling and ending with the methodology for opening and testing promising intervals.

As targets for deep prospecting drilling, from among the many structures of the depression, only those should be selected that are complicated by sharply expressed flexures on their flanks, passing at depth into faults. Such positive structures in the depression are: Zapadno-Tatarskaya, Altaiskaya, Bystryanskaya, Novo-Mikhailovskaya, Solzavodskaya, Petrashilovskaya, and others.

It is necessary to drill through zones of fracturing associated with flexures. The most promising fractured intervals should be in the places where a flexure passes into a fault.

1. Since the rocks are strong and the walls of boreholes do not cave in, promising fractured intervals should be tested not in an uncased borehole, but with the use of a filter. This method is successfully used in the oil fields of the Carpathians.

There are grounds to suppose that blasting does not achieve the desired effect because of the further compaction of strong but non-brittle rocks, such as the rocks of the South Minusinsk depression. During blasting, the transmission of pressure occurs instantaneously, and therefore it may be assumed that a large part of the energy is spent on destroying the casing, while it does not propagate into the bed for the necessary distance. It is another matter if the bed is ruptured gradually, as is achieved by hydraulic fracturing of the bed. In the latter case, the fractures present in the rocks (even closed ones) will expand and new fractures will form, whereas during blasting not so much are new fractures formed as existing ones are closed.

LITERATURE

1. Geological Structure of the Minusinsk Depressions and Prospects for Their Oil-and-Gas Potential. Collective of authors, edited by N. G. Chochia. Gostoptekhizdat, 1958.

2. B. N. Krasilnikov, Ya. G. Kats. The Significance of Fracture Zones for the Search for Oil Pools and Certain Questions of the Oil-Bearing Capacity of the Minusinsk Depression. Izvestiya vysshikh uchebnykh zavedenii, series Geology and Exploration, No. 9, 1959.

3. N. A. Lizalek. Petrographic-Mineralogical Characteristics of the Lower- and Middle-Devonian Deposits of the South Minusinsk Depression. Transactions of SNIIGGiMS, issue 1. Gostoptekhizdat, 1959.

4. Oil Production Reference Book. Gostoptekhizdat, 1958.

5. Fractured Rocks and Their Reservoir Properties. Transactions of VNIGRI, issue 121. Lengostoptekhizdat, 1958.

6. S. I. Shipigin. Reservoir Properties of Flysch Deposits of the Folded Zone of the Carpathians. Candidate dissertation. Archives of the Lviv Polytechnic Institute, 1954.