carbonate tight zones detection and their impacts on...

Research Article

March 2017

© 2017, IJERMT All Rights Reserved Page | 21

International Journal of

Emerging Research in Management &Technology

ISSN: 2278-9359 (Volume-6, Issue-3)

Carbonate Tight Zones Detection and Their Impacts on Bangestan

Reservoir Quality, Ahvaz Oil Field, SW Iran

Abstract—

ydrocarbon reservoir heterogeneity evaluation is a main point to infer reservoir and nonreservoir intervals

to predict reservoir behavior. The present research work is an attempt to interpret the presence of tight

horizons using NMR and conventional well logs, petrographic thin sections and core analysis data in the

Bangestan sequence of Ahvaz oil field, SW Iran. It is also discussed probable factors involvement in tight horizons

formation. The sedimentary sequence consists of Ilam and Sarvak formations. The Ilam and Sarvak formations have

divided into 3 and 7 reservoir zones, respectively. The sequence is mainly calcareous with intercalations of shale.

Porosity development is weak in the Ilam but dense-weak-fair in the Sarvak reservoirs. Formations both are consisted

of oil bearing interlayers in porous parts. Net thickness, net/gross, total porosity average and effective hydrocarbon

column are 108.2m, 0.586, 11.6% , 15.8%, and 10.6m for the Ilam Formation, and 492.3m, 0.66, 8.7%, 23.7%, and

32.7m for the Sarvak Formation, respectively. The results indicated that mudstone, mudshale, wackestone, packstone,

and grainstone are composed the Bangestan reservoir. Compaction, dolomitization, recrystallization, pressure

solution (stylolitization) are main diagenetic processes. Distribution lithofacies indicated variations which are

resembled depositional environmental instability. Mudstone and wackestone are dominated in upper part while with

increasing depth it replaced by wackestone, packstone and grainstone. Wackestone and mudstone also formed basal

part of the reservoir. It seems subzone C2 of the Ilam Formation must be having the best reservoir quality due to lack/

less quantity of clay in composition. It is suggested that depositional (the presence of mud and shale and their later

alteration) and post depositional (recrystallization and asphaltene deposition in pores) factors are responsible to create

tight horizons.

Keywords— NMR log, core data, Bangestan reservoir, Ahvaz oil field, petrophysical parameters

I. INTRODUCTION Reservoir rock evaluation has an important role in petroleum industry. Petrophysical methods capability and

petrographic study as complementary method are important to recognize reservoir zones in view of petroleum geology.

Tight zones are considered as a new aspect of hydrocarbon reservoir in the world [1]. Tight zones define to have low

permeability which is commonly less than 0.1 md. Recently, this limit was extended to less than 0.6md by the

Association of Coal and Oil Sciences and Technology of Germany. In the case of ultra-tight it will be decreased to

0.001md [2]. However it seems these values related to economic condition to decide to hydrocarbon production from

these discrete potential zones [3]. Tight zones are in type 3 of Williams classification [4] based on differences of

hydrocarbon accumulation physics. Unconventional tight sandstone and gaseous shale are included [5].Therefore,

permeability is a critical factor in the reservoir classification [2 and 6].

There are complexity in decline long life behavior of gas and oil tight zones [7] and on the basis of 25000 wells

studies it is suggested that these type of reserves are in appraisal step [8] and it may not find any ideal reservoir in the world [9].

Lithological, porosity, permeability and water saturation determination are doing by petrophysical studies [10].

The estimation of these factors can be done by well logs, well tests and corrected by core analysis data to find

hydrocarbon potential and reservoir parameters evaluation [4, 10- 14]. Fluid characteristics play an important role in

decision of reservoir [15]. Fluid movement in porous media is controlled by structural parameters [16]. All attempts

made to find an analytical relation between porosity and permeability are failed and not terminated to suitable results

[17]. However, there are new methods based on geostatical simulation to determine and estimation of secondary porosity

and permeability [18]. Their spatial distributions are possible affected by sedimentary units of the reservoir structure [12

]. The importance of pay zones evaluation [19-21] indicated that the prediction of controlled factors of reservoir quality

is important key in development program of any field [ 6, 9, 22-23]. Lithfacies changes and diagenetic processes

intensity are basic factors of controlling the reservoir quality [24]. The present paper is an attempt to decipher the effects

of theses in relative productivity and tight zones formation.

II. OIL FIELD UNDERSTUDY The Ahvaz oil field (Fig. 1) is one of giant oil filed in the Dezful Embayment, SW Iran. The Bangestan reservoir

(Cenomanian-Santonian) consisted of Ilam and Sarvak limestones which are deposited in a shallow or nerithic

Masoud Soleimani

MSc Student, Geology

Dept., Shahid Chamran

University of Ahvaz , Iran

Bahman Soleimani*

Prof. in Petroleum Geology,

Shahid Chamran University

of Ahvaz , Iran

Bahram Alizadeh

Prof. in Petroleum Geology,

Shahid Chamran University

of Ahvaz , Iran

Iman Veisy

Geology Dept.

National Iranian South Oil

Company (NISOC), Iran

H

Soleimani et al., International Journal of Emerging Research in Management &Technology



environment [25]. Dezful Embyment is a part of Zagros fold belt in the nourth east of Arabian Plate [26-27]. Thickening of this area caused by collision between Central Iran and Arabic plate [28-32]. The field extended for 65 km and 4-6 km

that were measured based on top of the Bangestan reservoir.

The Bangestan sequence was divided into 10 zones [33]. Zones A, B, and C belong to Ilam Formation and zones

of D, E, F, G, H, I, and J are consisted the Sarvak Formation (Fig. 2).

Fig. 1- Geographic position of Ahvaz oil field [34] and UGC map of the reservoir along with the position of drilled well

understudy.

Fig. 3-The Bangestan reservoir zones (after [33]) with lithofacies changes in one of selected drilled wells of the field.




III. METHODOLOGY

To evaluate reservoir parameters such as porosity, permeability and capillary pressure, different well logs (NMR

and conventional logs), core analysis data, thin sections petrography were used.

Nuclear magnetic resonance (NMR) with CMR tool was run in selected drilled wells of the Ahvaz oil field.

These data were processed by 7 steps as follow:

1- Quality control was made by Schlumberger company standards in view of calibration, tuning, and raw data

quality, repetition of NMR results and congeniality of data with other available log data. Most of the quality

control functions can be performed at the well site [35].

2- Derivation of NMR properties of fluids [36] requires the measurement of the NMR responses of fluids which

are different in view of fluid type.

3- NMRdata processing requires to applicable raw NMR data (time domain -FID) which are usually negative and

positive integers (real and imaginary) [37-38]. However, each NMR instrument has its own software for data processing[37].

4- NMR data inversion is necessary to obtain the T2 amplitude distribution from the T2 echo train signal [39].

5- Hydrocarbon analysiscan be determined using NMR spectroscopy depend on different echo spacings and wait

times [40-41].

6- Interpretation of T2distributions were used to predict permeability variation [42].

7- Modelling based on NMR data acquisition in carbonate rocks is very complicated [43]. Data can be used to

model the main reservoir parameters such as permeability and pore size.

The corrected data were formed input data of Geolog software (6.7.1) to process formation evaluation. Besides

of NMR log data, to verify and check data the following tools were also used.

Conventional well logs used are including gamma ray (GR), natural gamma ray spectroscopy (NGS), neutron log (NPHI), density (RHOB), sonic (∆t), resistivity (Rt) and caliper. These logs were applied for lithological

interpretation and porosity variation.

Core analysis was carried out by using 225m rock samples subjected to special core analysis (SCAL) to

understand saturation, porosity and permeability variations.

Petrographic study was made on the basis of 255 thin sections using optical petrographic microscope.

Lithological variation and diagenetic processes were interested.

IV. DISCUSSION

It is documented that three basic factors play an important role in controlling of reservoir zones quality

including sedimentary, diagenetic and pores type [21].

A. Petrophysic and Petrographic Characteristics

Formation evaluation of Bangestan sequence in one of drilled wells carried out by NMR log, conventional logs

and petrographic thin sections indicated the following main points related to the reservoir zones (Table 1, Fig. 4-

petrophysical parameters and zones):

Ilam Formation-Zone A is marked by wackestone or clayey limestone showing recrystallization (Fig.5A) and

glauconite mineral (Fig. 5A) which is indicating disconformity during late of Cretaceous [44]. The subzone is

characterized by less porosity development and lack of net hydrocarbon column.

Zone B consisted of compact pure limestone-mudshale with less oil staining (Fig. 5B) and weak development of

porosity. Net thickness, net/gross thicknesses, averages of porosity, water saturation, and hydrocarbon column were

measured 0.2m, 0.022, 7.8%, 35.6% and 0.01m, respectively.

Zone C divided into three subzones. Subzone C1 defined as pure limestone with oil staining with laminations

(Fig. 5C2) and fair-intermediate development of porosity. Net thickness, net/gross thicknesses, averages of porosity,

water saturation, and hydrocarbon column were measured 45m, 1.0, 13.1%, 13.8% and 4.2m, respectively. Subzone C2 is

lithologically similar to subzone C1, but having dolomite automorph crystals (Fig. 5C), and net thickness, net/gross

thicknesses, averages of porosity, water saturation, and hydrocarbon column are 39.9m, 1.0, 12.1%, 13.3% and 4.2m, respectively. Subzone C3 consisted of compact pure limestone with burial dolomite (Fig. 5D) with less quantity of clay

and shally layer at base having lamination. The subzone presents fair development of porosity and hydrocarbon in porous

layer and sometimes high relative water saturation. Net thickness, net/gross thicknesses, averages of porosity, water

saturation, and hydrocarbon column were measured 32.2m, 0.3, 8.1%, 28.2% and 1.4m, respectively.




Fig. 5-Mirophotographs of selected thin sections of the Bangestan reservoir zones in one of drilled wells: (A)

Recrystalized mudstone with glauconite (Z-A, 3276m); (B) oil accumulated along microfractures in mud shale (Z-B,

3284m); (C) mudstone with auto morph crystals of dolomite (SZ-C2, 3354m); (D) mudstone with burial dolomites (Z-

C3, 3444m); (E) mudstone with lamination and amygdaloidal structure (Z-D, 3464m); (F) mudstone-packstone (SZ-E1,

3558m); (G) packstone showing calcite filled intraparticle pores (SZ-E2, 3628m) (H) recrystalized wackestone and

fossils ghost (SZ-E2, 3652m); (I) packstone indicating stylolite with oil stain (SZ-E2, 3684m); (K) wackestone (SZ-F1,

3710m); (L) mudstone with oil stain and stylolite (SZ-G2, 3878m); (M) laminated mudshale (Z-H, 3956m); (N)

grainstone (SZ-I-1-1, 4040m); (O) packstone (SZ-I-1-2, 4090m); (P) dolostone with oil stain (SZ-I-2, 4170m). Depth

is per meter (m).

Sarvak Formation-Zone D consisted of mudstone with stylolite and bioturbation structures indicating fractures and amygdaloidal structure due to compaction (Figs. 5E) with oil staining in porous layer and less quantity of shale and

dense –fair development of porosity. Net thickness, net/gross thicknesses, averages of porosity, water saturation, and

hydrocarbon column were measured 24.1m, 0.525, 8.8%, 19.6% and 1.7m, respectively.

Zone E divided into two subzones. Subzone E1 defined as packston-grainstone indicating dolomitic cement and

hydrocarbon filled stylolite (Fig. 5F), glauconite peloidal packstone. It is observed that dolomite filled pores. The

subzone subjected to fair-dense development of porosity. Net thickness, net/gross thicknesses, averages of porosity,

water saturation, and hydrocarbon column were measured 64.6m, 0.72, 9.2%, 20.5% and 4.7m, respectively. Subzone E2

is similar to subzone E1 consisted of wakestone–mudshale and sometimes packstone. Fossil molds were filled by calcite.

Intense recrystalization causes to convert fossils to form ghost shape, hydrocarbon staining and filled fractures,

lamination and also amygdaloidal structure are observed (Figs. 5G-I). Net thickness, net/gross thicknesses, averages of

porosity, water saturation, and hydrocarbon column are 87.2m, 0.8, 6.8%, 23.6% and 4.5m, respectively.

Zone F divided into two subzones. Subzone F1 defined as wackestone-mudshale with scarce dolomite and oil staining and sometimes wackestone with calcite filled fossil mold (Fig. 5K). Well tests indicated hydrocarbon bearing

porous layer and intermediate-dense development of porosity. Net thickness, net/gross thicknesses, averages of porosity,

water saturation, and hydrocarbon column are 4.3m, 0.12, 8.0%, 33.1% and 0.2m, respectively. Subzone F2 is similar to

subzone F1 and net thickness, net/gross thickness, averages of porosity, water saturation, and hydrocarbon column are

27m, 0.6, 8.4%, 21.9% and 1.8m, respectively.

Zone G divided into two subzones. Subzone G1 defined as mudstone–mudshale with stylolite (Fig. 5L) and

hydrocarbon stain. Well logs and tests are indicating hydrocarbon bearing layer and intermediate-fair development of

porosity. Net thickness, net/gross thicknesses, averages of porosity, water saturation, and hydrocarbon column are 28.1m,

0.95, 9.3%, 16.6% and 6.4m, respectively. These parameters are measured in subzone G2 as 72.4m, 1.0, 10.6%, 18.5%

and 6.2m, respectively.

Zone H consisted of mudshale (Fig. 5M) with oil bearing layers and weak-dense development of porosity. Net thickness, net/gross thicknesses, averages of porosity, water saturation, and hydrocarbon column are 10.5m, 0.32, 5.6%,

36.2% and 0.4m, respectively.




Zone I divided into two subzones. Subzone I-1 is grainstone (Fig. 5N) with hydrocarbon bearing layers and intermediate-fair development of porosity which is varied as weak-intermediate development porosity in subzone I-1-2

(packstone, Fig. 5O). Net thickness, net/gross thicknesses, averages of porosity, water saturation, and hydrocarbon

column are 74.2m, 0.87, 9.0%, 30.3% and 4.6m, respectively while are different in subzone I-1-2 as 23m, 0.45, 8.5%,

42.2% and 1.1m, respectively. These parameters in subzone I-2 are 22.9m, 0.32, 7.6%, 43.7% and 1.0m, respectively.

Subzone I-2 consisted of mudshale, packstone with stylolite and dolostone (Fig. 5P).

Zone J consisted of pure limestone with weak-dense development of porosity and without hydrocarbon column.

Therefore, this subzone is behind of hydrocarbon interest.

B. NMR data

CMR tool was used to formation evaluation in nuclear magnetic acquisition data. The most important factor is

T2 or relaxation time which is an indicator of grain size and permeability. This factor increases as permeability / grain size increases and decreases they reduced while capillary fluid is high. T2 plots, free fluid plot and compound capillary

pressure plot (Fig. 6) revealed that permeability is low in zone A of Ilam Formation which is estimated about 0.08 in

SDR model and 0.018 in Timur model. In this zone free fluid is near zero.

In zone B, permeability is near zero at top but gradually increases as at base is around 1 md and 0.5md based on

SDR and Timur models respectively. Permeability average is 0.15 (SDR) and 0.08 md (Timur). Free fluid is going to

increase in this zone. This pattern could be ascribed to decrease of clay content and increasing of grain size. In other

words it concerned to washing (agitation) process of lithofacies due to depositional environment variation.

The last zone of Ilam Formation is Z-C that the best reservoir quality is detected in subzone C2 (Fig. 7).

Petrophysical evaluation results are indicating (Fig. 8). Petrographic study indicated that SZ-C2 consisted of less quantity

of clay in comparison to other subzones. The presence of sparse dolomite may be a role in introducing of heterogeneity.

Permeability means of Zone C in SDR model are 48.65, 54.01, 12.95, and in Timur model are 36.98, 38.6 and

3.16, for C1, C2, and C3, respectively. In top of the Sarvak Formation permeability exhibited drastic decrease as at top of zone D is zero but permeability mean in zone D is 6.7md and 0.48md in SDR and Timur models, respectively.

Permeability variations in SDR and Timur models indicated that Timur results are less than SDR data (Fig.9).

Fig. 6-Comparison of lithological, permeability and free fluid volume variations in drilled well understudy.




Fig. 7-NMR log presenting the best reservoir quality of the Ilam Formation is zone C.




Fig. 8- Petrophysical evaluation results of drilled hole understudy.

Regarding to T2 mean plot, there are horizons with high compaction and very low permeability (Fig.10) in

different depths such as 3279-3284, 3413-3420, 3429-3443, 3446-3450 and 3460-3464 that most of them are in the

Sarvak Formation. Theses horizons resemble lamination (micro-fracture) and amygdaloidal structure due to diagenetic

compaction with oil staining in some depths.

It seems the following reasons played an important role to create tight horizons based on all present data:

- increasing of matrix causes to reduce pore throats and so disconnect pores [45].

- Lithofacies effects due to depositional environment changes while the Bangestan deposition.

- Mud filtration which is occurred during diagenesis and deposited in pores in lower parts.

- Diagenetic processes such as recrystallization, stylolites and compaction and thus destruct the original porosity

[46-47].

- Asphaltene deposition in micro-fractures.

- Disconformity event and hard ground generation.

- Plasticity behavior of limestone and so low fracturing potential.

It is appeared that the reservoir quality decreased with increasing of shale volume according to comparing of

lithologic column, permeability and free fluid column. Therefore, shale volume not only affected on permeability and

free fluid but also helped to more compact or amygdaloidal formation.




Fig. 9-Permeabilty-depth variation based on SDR and Timur models in the Bangestan reservoir of Ahvaz oil field.

Fig.10- Tight zones in the Bangestan sequence of the Ahvaz oil field

V. CONCLUSION

The Bangestan sedimentary sequence consists of the Ilam and Sarvak formations in Ahvaz oil field. It is divided

into 10 reservoir zones that among 3 of them belong to the Ilam Formation and 7 zones are in the Sarvak Formation.

Lithologicaly the sequence is calcareous with intercalations of shale. The Ilam reservoir characterized with weak porosity

development but oil bearing in porous horizons. The Sarvak reservoir presents dense-weak-fair porosity development

with oil bearing interlayers. In view of formation evaluation, net thickness, net/gross, total porosity average and

effective hydrocarbon column are 108.2m, 0.586, 11.6% , 15.8%, and 10.6m for the Ilam Formation, and 492.3m, 0.66,

8.7%, 23.7%, and 32.7m for the Sarvak Formation, respectively. The Bangestan reservoir is composed of mudstone, mudshale, wackestone, packstone, and grainstone. Among

diagenetic processes, compaction, dolomitization, recrystallization, and pressure solution (stylolitization) can be cited.

Lithofacies distribution indicated that upper part of the reservoir marked by dominating of mudstone-wackestone.

Wackestone, packstone and grainstone are dominated by increasing depth. Wackestone and mudstone are formed major

constituents at base. Among the reservoir zones it seems subzone C2 belong to Ilam Formation is the best reservoir

quality due to lack/ less quantity of clay in comparing to other zones.




Permeability variation to depth exhibited the presence of tight horizons which are not developed well. Most of these horizons are in the Sarvak reservoir. It is suggested that the presence of mud and shale and their later alteration and

transformation to lower zones not only destroyed original porosity but also prevented to extend fractures during

deformation period and decreasing permeability. Destructive processes of diagenesis such as recrystallization and

asphaltene deposition in microfractures and pores resulted to create tight horizons.

ACKNOWLEDGEMENTS

The authors wish to express their gratitude for financial support of National Iranian South Oil Company and

Research Manager of Shahid Chamran University of Ahvaz, for financial, support and encouragement. And we also

express frankly thanks to anonymous referees for their critical points to improve the quality of the paper.

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http://dx.doi.org/10.4236/ojg.2016.63018

http://www.sciencedirect.com/science/journal/10907807

http://www.sciencedirect.com/science/journal/00162361

carbonate tight zones detection and their impacts on...

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