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УДК 552.578.2 О.М. Эхигиатор
Университет Бенсон Айдахоза, Нигерия Р.А. Эхигиатор-Иругхе СГГ А, Новосибирск И. Аигбедион
Университет Амброза Али, Нигерия
ПОСТРОЕНИЕ ГЕОЛОГИЧЕСКОЙ МОДЕЛИ МЕСТОРОЖДЕНИЯ НЕФТИ С ИСПОЛЬЗОВАНИЕМ ПЕТРОФИЗИЧЕСКИХ ПАРАМЕТРОВ И ДАННЫХ КЕРНОВОГО АНАЛИЗА (НА ПРИМЕРЕ МЕСТОРОЖДЕНИЯ АБУРА В БАССЕЙНЕ ДЕЛЬТЫ РЕКИ НИГЕР)
0.M. Ehigiator
Benson Idahosa University, Nigeria E-mail: Geosystems_2004@yahoo.com R.A. Ehigiator - Irughe PhD Student, SSGA, Russian Federation E-mail: raphehigiator@yahoo.com
1. Aigbedion
Ambrose Alli University, Nigeria.
E-mail: isaacaigbedion@yahoo.com
CHARACTERISATION OF RESERVOIR USING PETROTROPHYSICAL PARAMETERS AND CORE DATA (A CASE STUDY OF ABURA FIELD NIGER DELTA OF NIGERIA)
Abstract
The computation of petrophysical parameters for two wells in Niger Delta basin of Nigeria and comparison with the results of core data analysis are described in the paper. Geophysical logs data set comprising gamma - ray, spontaneous potential, electrical resistivity, neutron and density logs from the wells were evaluated for its hydrocarbon potential. The formation evaluation of wells was performed to identify the hydrocarbon bearing reservoir and study the reservoir properties based on well data. The wells studied contain sufficient data to allow for detailed analysis including porosity, water saturation, permeability and net- to-gross hydrocarbon. However, the consistency of results was checked using core data. From analysis the porosity was found to range from 20 to 27 %, permeability was found to range from 22 to 80md, while water saturation was found to range from 37 to 75 %, hydrocarbon sand range from 2245 to 2943m.
Key words: Density logs, spontaneous potential logs, porosity and permeability. Introduction
The Abura field is located in Niger Delta Basin of Nigeria. The Niger Delta formation consists of sands and shale with the sands ranging from flurial to fluviomaire while the shale is either fluviomaire or Lagoonal. The Niger Delta oil province is characterized by approximately east - west trending synsedimentary faults and folds called growth fault with roll over anticline. These formations are
mostly unconsolidated and not easy to carry out core analysis or drill stem test (DST).
A good formation evaluation must encompass the following: well logs, core analysis and mud logs. Mud logs are done simultaneously while drilling activity is in progress. Core analysis is also carried out while drilling with the help of core barrels used to capture the formation and then taken to the laboratory for analysis. The geophysical well logs are run in hole before and after casing and from these three analyses, the petrophysical parameters are determined. Three major lithostratigraphic formations are recognized in the Niger Delta: the Benin, Agbada and Akata formation [1].
The Benin formation is loose with fresh water bearing sand with occasional ligrire and clay with depth of about 2,286m and no over pressures. The Agbada formation consists of two alternations of sands and shale [2]. The Agbada formation contains sands that are mostly encountered at upper parts while shale is found in the lower parts. The Agbada formation is the thickest at the center of the Delta goes up to about 457.2m. This is the formation that is of importance to the petroleum company which is the seat of most reservoirs and associated with high pressure [3]. The Akata formation is the deepest of the three formations and is mostly water bearing formation.
The reservoir rocks encountered in this research were mainly dolomites which were calcareous. Though 50 % of most reservoir rocks are carbonate, the porosity of the rock matrix was estimated as well as the permeability. It is important to know that not all porous rocks are permeable, but all permeable rocks are porous. Permeability which is the ease with which fluid flows out of the rock matrix is associated with the interconnected pores.
The evaluation of petrophysical parameters of two wells in the Niger Delta using geophysical well log data and their comparison with the core data and mud logs are considered.
Materials and Methods
The services of Schlumberger group was employed to carry out the open hole and cased hole well logs. The following logs were run in hole by Schlumberger: gamma ray, spontaneous potential, resistivity, and neutron and density logs. The gamma ray and spontaneous potential were used to determine the lithology. The neutron and density logs were used to estimate the porosity of the formation. The resistivity logs were used to determine the water saturation of the reservoir.
The permeability was estimated using the Timur equation documented by Western Atlas (1982):
where: K - permeability (millidarcy), $ - porosity (in %), Swi - irreducible water saturation.
The parameters of the two wells analyzed are presented in Tables 1 and 2.
(1)
Well reservoirs Well Interval (m) Thickne ss (m) Porosit y % Porosity (core) % Md Permeability Water Saturation (%)
A 2245 -2258 13 22 21 80 37
B 2377 -2412 35 20 21 53 37
C 2578 -2583 5 23 22 41 57
D 2622 -2627 5 25 26 34 75
E 2638 -2641 3 27 26 48 75
F 2679 -2683 5 22 24 22 71
G 2709 -2713 4 23 20 45 54
H 2874 -2880 6 21 21 37 60
I 2939 -2943 4 23 24 33 52
Table 2 - Hydrocarbon reserve for Well B
Well reservoirs Well Interval (m) Gross Thickness (m) Porosit y % Porosity (core) % Permeability (K) (md) Water Saturation (%)
A 2510 -2518 8 23 26 130 32
B 2532 -2542 10 26 24 238 31
C 2649 -2658 9 24 22 101 40
The oil water contacts (OWC) were determined using the resistivity logs and a combination of neutron - porosity and Bulk density logs. Using Archie equation, the water saturation was carried out. The porosity value were obtained using
(p = (yD +pN )/2 (2)
where: 9d - porosity obtained from density logs, ^N - porosity obtained from neutron logs.
It is known that
<pD = Pma Pb x 100
Pma ~ Pf
pf = 1 since the density of water - 1 pma = 2.65 (constant for sand stones)
pb is a bulk density and taken directly from the density log. The values were obtained at the points in the reservoir and their mean is taken. This was done in order to increase the accuracy. ^N was taken directly from the neutron log and from three different positions and the mean was taken to increase the accuracy.
The Archie equation was used to determine the water saturation thus:
where: Sw - water saturation, O - porosity, Rw - formation water resistivity, a - tortuosity,
m - cementation factor, n - saturation exponent.
Reservoir Evaluation
The estimation of hydrocarbon in place (OIP) was performed using:
where: VB - Area within the contour multiplied by the thickness h, VB- bulk rock volume containing hydrocarbons, 0 - mean porosity of hydrocarbon bearing rock.
Using the above equation, estimated hydrocarbon reserve for two reservoirs
is:
Well A = 42,321,318,779 bbls
Well B = 3,480,822,544 bbls
Conclusion
All the sands are homogenous within pay thickness. The two wells were found almost homogenous implying that between the two wells is a connection. The analysis of GR and SP logs shows that the overall lithology is an alternation of sand and shale which is an attribute of the Agbada formation. Most importantly, there were similarities between values of porosities obtained from the calculation approach and those from the core analysis.
From the results obtained, the water saturation, porosity, permeability and pay thickness, the reservoirs are prolific and good enough for commercial accumulation of oil and gas in the Niger Delta.
(4)
VH = AH$(1 - Sw)
(5a)
VH = AB0(1 - Sw)
(5b)
References
1. Ehigiator - Irughe, R. (2002) “Mathematical Methods for Determination of Oil Water Contact”. PGD Thesis. Department of Petroleum Engineering, University of Benin, Benin City.
2. Ekweozor, C. M. and Dakoru, E.M; 1984, Petroleum Source Bed Evaluation of Geologists V.68, p. 1744-1751.
3. Evamy, B.D., Haremboure, J. and Kamerling, P., Hydrocarbon Habitat of Tertiary Niger Delta: American Association of Petroleum Geologists Bulletin, V. 62, P. 277-298.
4. Beka, F.T. and Oti, M.N., 1995, The Distal Offshore Niger Delta: Rotterdam A.A. Balkema, p. 237 - 241.
5. Western Atlas; Oil and Gas Journal, 1982 p. 101-103.
© O.M. Эхигиатор, P.A. Эхигиатор-Hругхе, H. A^6eduoH, 2010
