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Forecasting cracked collectors on anticlinal type structures at late stage
of exploration in oil and gas area
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IPDME 2017 IOP Publishing
IOP Conf. Series: Earth and Environmental Science 87 (2017) 052008 doi :10.1088/1755-1315/87/5/052008
Forecasting cracked collectors on anticlinal type structures at
late stage of exploration in oil and gas area
M A Hasanov
1,3
, B L Aleksandrov
2
, A S Eljayev
1,3
, Т В Ezirbaev
1,3
, S S Gatsaeva
1
1
Grozny State Oil Technical University named after academician M. D.
Millionshchikov, T100, Isaeva Av., Grozny, 364051, Russia
2
Kuban State Agrarian University named after I.T. Trubilin, 13, Kalinina Av.,
Krasnodar, 350044, Russia
3
Kh. Ibragimov Complex Institute of the Russian Academy of Sciences, 21a,
Staropromyslovskoe shosse Av., Grozny, 364051, Russia
E-mail: geofizikggni@mail.ru
Abstract. The possibility of using complex information on morphological parameters of
structures, block porosity and the reservoir pressure gradient over previously explored deposits
for the development of a multidimensional equation for estimating secondary porosity is
considered. This is examined by the example of reservoirs with secondary (fractured) porosity
of the Upper Cretaceous carbonate deposits of the Tersko-Sunzhenskaya oil and gas bearing
region of the Ciscaucasia. The use of this equation makes it possible to predict the magnitude
of the secondary porosity on the anticlinal structures, which are newly discovered by seismic
methods at a later stage of exploration in the relevant oil and gas region, as a quantitative
criterion that predicts the presence of a trap.
1. Introduction
First-order exploration and development of the largest deposits are usually discovered and introduced
into exploration in each oil-and-gas bearing region, as a rule. Later structures of significantly smaller
sizes are introduced into exploration, which do not always have effective traps for the accumulation of
hydrocarbons. In this connection, at the final stage of exploration in the region, especially when
drilling on deep-lying horizons, it is important to determine the quantitative criteria that allow
prediction of the presence of a trap in order to assess the expediency of introducing new, sometimes
low-amplitude, anticline structures into exploration. This is primarily determined by the presence of a
potential collector with a secondary porosity of the fracture type and the possibility of the influx of
hydrocarbons from them. Therefore, it is important to select the locations of the exploratory and
exploratory wells most reasonably when searching for hydrocarbon deposits in the sedimentary cover,
associated with the secondary reservoirs of the fractured type of anticline structures.
2. Materials and methods
According to the modern theoretical concepts of the mechanism of formation of fractured reservoirs,
the strength of the secondary (fractured) porosity of the carbonate strata is mainly influenced by the
strength properties of the rocks, the morphology of the folds, and the formation pressure. There are a
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IOP Conf. Series: Earth and Environmental Science 87 (2017) 052008 doi :10.1088/1755-1315/87/5/052008
number of methods for predicting the zones of development of fracture reservoir rocks that have their
own both positive and negative features, the main ones being the lack of the full use of information.
It is proposed to use information on previously drilled structures at a later stage of exploration in a
specific oil and gas area to increase the efficiency of hydrocarbon deposits prospecting by predicting
the presence of fracture zones and optimizing the location of exploratory and exploratory wells on
anticline-type structures. To do this, it is necessary to use information on morphological features of
structures, block porosity of rocks and reservoir pressure values in a complex manner. The solution of
this problem is considered below for the example of the Upper Cretaceous deposits of the Tersko-
Sunzhenskaya oil and gas bearing region).
To test the method for predicting the presence of fractures on structures of the anticlinal type,
information was used on 15 deposits of the old foundation of the drilled structures of the Tersko-
Sunzhenskaya oil and gas region (Table 1). The depths of folding locks (H), the morphological
parameters of the structures, including the maximum formation bend (i), width (M), length (L), area
(S), folding intensity (J = i / S) were determined. Based on the results of field and geophysical studies
of the wells of these deposits, taking into account petro physical studies of cores using the developed
techniques [1, 2], the values of the total (PHIpb), block (PHIpb), secondary (PHIsp) porosity used in
the calculation of reserves, and reservoir pressures were defined based on the test results.
The results of statistical data processing for 11 thousand determinations of block (PHIpb) and total
(PHItp) porosity values from the depth of bedding showed that with a depth of occurrence the area-
weighted average values of both block and total porosity of the Upper Cretaceous rocks are reduced.
In addition, for each deposit, there is a general tendency to reduce the secondary porosity (PHIsp) of
rocks with depth (Figure 1). As can be seen, curves PHIsp = f(H) have their own peculiarities for the
structures, located at different depths of the Upper Cretaceous sediments; therefore, the change in the
average values of the secondary porosity with the depth as a whole for the Tersko-Sunzhenskaya oil
and gas region occurs according to the exponential law PHIsp = 5.2 · е
-0,508Н
with a correlation
coefficient of 0.725.
The influence of various morphological parameters, including flexure of the folds, under which
tensile stresses, forming the development of fracturing, appear, has been revealed [3,4]. Moreover, the
relationship between the bending of the strata (i) in the Upper Cretaceous folds and the secondary
porosity (PHIsp) is described by the equation PHIsp = 0.46 • i
1.5
with a correlation coefficient of 0.6.
As can be seen (Figure 1), the nature of the change in the secondary porosity for the differently
loaded structures is not the same, and therefore the correlation coefficients of the ratios PHIsp = f (H)
and PHIsp = f (i) are not high.
Figure
1
. Change of the secondary
porosity of Upper Cretaceous rock
formations with a depth of occurrence.
Areas: 1 - Karabulak-Achalukskaya; 2 -
Zamankul; 3 - Benoiskaya; 4 - Malgobek-
Gorskaya; 5 - Khayan-Kortovskaya; 6 -
Eldarjvskaya; 7 - Starogroznenskaya; 8 -
Gorayacheistochinskaya; 9 - North-
Malgobekskaya; 10 - Agunskaya; 11 -
Pravoberezhnaya; 12 - Mineral; 13 -
North-Mineral
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Table 1. The results of the evaluation of the morphological parameters of the structures and secondary
porosity values adopted in the State Commission for Mineral Resources (SCMR) in the calculation of
reserves, used to derive the multivariate regression equation
Areas
Hipsometry of the
lock H
.
km
Length L. km
Width M. km
Height N. m
Bending i. m
Area S. km
2
Elongation ∆ = L /
M
Intensity J=i/S.
m /
km
2
Radius R. km
Grad.10-2MPa/ m
Kpb.%
PHIsp (SCMR)
Malgobek-Gorskaya
Karabulak-Achaluksky
Starogroznenskaya
Zamanculskaya
Eldarovskaya
Khayan-Kortovskaya
North-Malgobek
Bragunskaya
Hawk
Gudermesskaya
The October’s
Mineral
Right-bank
North-Mineralnaya
Benoiskaya
2.2
1.1
3.6
1.2
3.4
2.9
4.04
4.0
3.7
4.6
4.0
4.6
4.5
4.8
1.3
46
40
28
32
35
40
22.5
42.5
31
23.5
36
21
34
18
28
3.2
3.5
2.5
3
3.5
2.6
4.3
3
2.4
2.0
2.5
3
3.5
2.2
4
600
1100
600
400
800
700
160
1200
1100
200
1200
600
700
200
400
1467
1890
1350
2050
920
1420
900
836
900
675
1533
800
1000
525
1075
112
140
75
92
89.7
81.5
86.2
96
56.2
50
86.7
55.1
91.6
32.8
64
14.37
11.43
11.2
10.67
10
15.38
5.23
14.17
12.92
11.75
14.4
7
9.71
8.18
7
13.10
9.28
18
19.5
10.26
17.42
11.81
8.71
16.01
13.5
17.68
14.52
10.92
16.01
11.41
2.9
2
1.7
3.5
1.8
1.4
1.3
1.2
1.3
1.55
1.1
2.1
2.15
2.0
2.95
1.85
2
1.65
1.6
1.58
1.65
1.43
1.52
1.62
1.4
1.53
1.4
1.46
1.36
2
7.2
15
3
13
3.6
4.2
2.2
2.1
2.8
1.6
2.2
1.6
1.8
1.4
12
0.8
0.66
0.67
0.57
0.62
0.86
0.57
0.6
0.8
0.5
0.6
0.38
0.46
0.36
0.65
3. Research results
To increase the reliability of the estimation of secondary porosity by the method of multiple
correlations, equations connecting the secondary porosity with two or more parameters are derived,
which are given in Table 2.
It is seen that with the complication of communication, the accuracy of determination PHIsp
increases. Therefore, to predict the magnitude of the secondary porosity exploration areas, it is
proposed to use first regression equation (4).
The proposed regression dependence was compiled using the least squares method by stepwise
linear regression, when at each step of the whole set of arguments the one that had the most significant
effect on the magnitude of the correlation ratio (R) was singled out. The analysis shows that the
absolute values of the partial correlation coefficients (r) are smaller than the magnitude of the multiple
correlation coefficient (R). Checking on Fisher criterion showed that the equations drawn up at each
stage stepwise regression, including in the last stage, are significant at the level of g = 0.05
significance.
Table 2. Types of PHIsp equations of dependence on the morphological parameters of the structure
and the values of the multiple correlation coefficients
Type of equations
№ The
coefficient
of multiple
correlation
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PHIsp = 0.04789J – 0.21792Н + 0,88930 (1) 0.795
PHIsp = 0.04736J – 0.20801Н + 0.10406 gradP + 0.70626 (2) 0.796
PHIsp = 0.04779J – 0.1881Н + 0.02487 PHIpb +0.03450 gradP+ 0.
66496
(3) 0.797
PHIsp = 0.00023i + 0.89506 grad P+0.02495J– 0,02577 PHIpb –0,06675Н –
– 0.94440
(4)
0.852
Based on the derived patterns of change in the secondary porosity, taking into account the
morphological characteristics of structures and the depths of their occurrence, it is possible to predict
structures that are prospective for drilling candidates in terms of availability of the headers. To do this,
it is necessary to determine the critical value of the secondary (fractured) porosity coefficient
corresponding to the "collector-noncollector" boundary.
4. Justification of the lower limit of secondary porosity for the collector-noncollector boundary
According to the results of complex study of drilling data, well test and geophysical surveys of wells
(GSW) materials, it was established that less than 0.2% oil inflows is not received at the value Upper
Cretaceous secondary porosity (PHIsp). This critical value of the secondary porosity (PHIsp.crit) for
the "collector-noncollector" boundary is derived by means of mathematical statistics methods. In the
statistical sample, the results of tests of 138 objects of all wells that opened Upper Cretaceous
sediments in the study area were used, of which there are 102 objects with reservoir intervals and 36
objects with intervals of non-collectors. Non-collectors include strata from which inflows of fluids
have not been received even after the creation of maximum permissible depressions on them and the
necessary processing of them. For reservoirs, the intervals of secondary porosity vary from (0-0.3)%
to (4.5-4.8)% with a quantization step of 0.3%, and for non-collectors, the secondary porosity intervals
vary from (0-0.05)% up to (0.55-0.6)% with a quantization step of 0.05%. The obtained data were
grouped into two tables. Distribution and processing of data were carried out using the method of
mathematical statistics.
Analysis of the distribution tables has shown that the actual average sample "collector", "non-
reservoir" absolute value different. Their average secondary porosity, respectively, 1.18% and 0.2%
with a standard deviation of 0.96% each and 0.17%.
Standard errors of these measurements for samples are respectively equal to 0.095% and 0.029%,
the probable errors - 0.064% and 0.019%.
Estimation accuracy of the correspondence of the actual average value of the true secondary
porosity was produced with a probability of 0.955, i.e., there were probable limits of the true value of
PHIsp, which are equal to the following values: -for "collectors" 0.99% ≤ PHIsp ≤ 1.37%; -for
«noncollector» 0.1365% ≤ PHIsp ≤ 0/2525%.
Comparing the distribution values for the polygons PHIsp for reservoir and non-reservoir of Upper
Cretaceous deposits with the theoretical curves of random variable distribution, an assumption that the
secondary porosity is distributed according to an exponential law f(PHIsp) = 1- e
λPHIsp
, (5), where λ -
given the failure rate is equal 1/ PHIsp, was made.
Moreover, the differential function of the expected exponential distribution is as follows: -for
reservoirs f(PHIsp) = 0.83- e
-0.83PHIsp
; – for «noncollector» f(PHIsp) = 5.1- e
-5.1PHIsp
.
To test the hypothesis of the correspondence of the experimental data to the exponential
distribution law, the Pearson agreement criterion was used.
To find the upper limit of the confidence interval of reliability criterion Upper Cretaceous quantities
expectation secondary porosity we adopted presence collector, equal to the upper limit of efficiency
exploration 0.7. To find the lower limit of the confidence interval of the expectation value of the
secondary porosity Upper Cretaceous defining critical PHIsp -non-reservoir layers, to avoid missing
fields, the calculation was conducted with maximum reliability 0.95. Significant differences between
the two sample variance was carried out using Romanovsky criterion.
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From the analysis of integral distribution curves secondary porosity values of formations "collector-
noncollector » (F,%), and curve reliability allocation noncollector (F%) (Fig. 2) that the critical
secondary porosity (P = 50%) is equal to 0.35%, and the accuracy of the separation reservoir and non-
reservoir at PHIsp ≤0.2% is ≥ 85%. Consequently, the lower limit of the secondary porosity (PHIsp
lim
)
for the "collector-noncollector" boundary for the Tersko-Sunzhenskaya oil and gas bearing region with
a probability of ≥ 85% is 0.2%, and the upper and lower limit of its confidence interval, taking into
account the efficiency of prospecting works – PHIsp/ PHIsp
lim
=(0.14/0.2)+(0.24/0.2)=0.7+1.2. Thus,
using the proposed criterion for separating reservoirs from the value of the critical value of secondary
porosity, it is possible to isolate the collector intervals according to the value of PHIsp calculated from
the GSW materials in a drilled well or the magnitude of the predicted secondary porosity on new
structures revealed by seismic methods. According to the results judged on the presence of collectors,
expediency statement drilling on this structure and order entry wells drilling, and with regard to:
PHIsp/ PHIsp
lim
>1.2 – It is advisable to drill along the profile in the optimal direction from 2-3
dependent wells;
PHIsp/ PHIsp
lim
= 0.7+1.2 – drilling a hole in the roof structure can be performed.
Thus, the critical value of the secondary porosity of 0.2% for the entire study area, and the upper and
lower limits of its confidence interval (PHIsp/ PHIsp
lim
= 0.7 + 1.2) mathematically well founded in
view of efficiency of exploration [5,6].
Figure 2. Integral curves of the
distribution of values of the
secondary porosity of collector-
noncollector reservoirs (F,%) and
the reliability curve of the extraction
of noncollectors
5. The discussion of the results
The practical implementation of the method was carried out using the example of the Upper
Cretaceous deposits of the Tersko-Sunzhenskaya oil and gas bearing area on new, undrawn anticlinal
structures.
For this purpose, according to a newly identified anticlinal structures determined by seismic data
locks depth, the amplitude and the linear dimensions of the structures and the presence of deep faults.
According to the schedule PHIpb = ƒ (H) determined bloc porosity, the experience of other structures
quantitatively evaluated the reservoir pressure and the formulas (1-4) multivariate correlation
secondary porosity PHIsp = ƒ (i, gradp, J, PBC H) calculated predicted value For each structure,
which was compared with the value of PHIsp
lim
. It assessed the prospects of 46 anticlinal structures
identified by seismic. The results of these calculations along with recommendations were transferred
to JSC "Grozneftegas" Some examples of these are given in Table 3.
It is noted that the most promising in terms of having reservoirs in Upper Cretaceous area are:
Sayasanovskaya, Mesketinskaya, North Benoyskaya, Syuretskaya, Datyhskaya, Goyevskaya, North
Dzhalkinskaya, Pravoberezhnaya (Southern), wherein the predicted value of secondary porosity is
between 0.52% and more. In the main parts of 12 structures (Belorechenskaya, Novolakskaya,
Granichnaya, Dzhalkinskaya, Severo-Bragunskaya and others), the predicted value of the secondary
porosity is 0.3% to 0.5%, and they are also promising.
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Table 3. Predictive values of secondary porosity Upper Cretaceous Tersko-Sunzhenskaya
oil & gas area
Areas
Depth of the castle
N, km
Paleo
-high i, m
Area structure S,
km2
Intensive Th J
=
= i / S, m / km2
Grad P,
10
-2МПа/м
PHI
bp
, %
PHI
sh
calculated by formulas
The average value
PHIsp
(1 - 4),%
GSW
PHIsp %
(1) (2) (3) (4)
North Benoyskaya 2.921 600 71.05 8.44 1.67 7.2 0.67 0.67 0.76 0.52
North
Eldarovskaya 5.076 200 28 7.14 1.35 1.6 0.13 0.13 0.11 0.13
North Bragunskaya 5.004 600 56 10.71 1.47 1.6 0.3 0.33 0,32 0.4 0,34 0.2
6. Conclusion
The proposed method for predicting the value of secondary porosity on structures of the anticlinal type
was obtained [7, 8] and it can also be used to search for deep-seated collectors with secondary porosity
in terrigenous strata that are not promising for prospecting deposits in granular-type reservoirs. From
the ratio of the predicted value of secondary porosity of the critical value it is possible to judge the
existence of effective traps feasibility drilling candidates on this structure and in the input order of
wells drilled [9, 10].
The economic efficiency of the proposed method is to reduce the cost of exploration of oil and gas
fields in deep-seated reservoirs with secondary porosity by justifying the appropriateness of drilling on
the small amplitude anticlinal structures identified by seismic methods and the order of well entry into
the drilling.
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