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Predicting Subsidence in the South Pars Gas Field, Iran

Mohammad Hossein Taherynia Department of Geology, Faculty of Sciences, Kharazmi University,

Tehran, Iran e-mail: MH.Taherynia@gmail.com

Akbar Ghazifard Department of Geology, Faculty of Sciences, University of Isfahan,

Isfahan, Iran e-mail: Ghazifard@yahoo.com

Seyed Mahmoud Fatemi Aghda Department of Geology, Faculty of Sciences, Kharazmi University,

Tehran, Iran e-mail: Fatemi@bhrc.ac.ir

ABSTRACT The focus of this study is to predict the subsidence of the South Pars gas field at the end of production period. With respect to the notable reservoir thickness, significant pressure drop due to extraction and high areal extent of the South Pars gas field there is a high potential for subsidence to occur in this field. In order to determinate the maximum land subsidence and subsidence profile of the South Pars gas field, at first, the reservoir compaction was estimated based on the thickness of the reservoir, the pressure drop in the reservoir, and the uniaxial compaction coefficient of the reservoir rock and then the effect of the reservoir compaction on the field surface was modelled with use of semi-numerical methods. The compaction of the reservoir at the end of production period was estimated to be about 0.48 m. The subsidence modelling methods predicted that the maximum subsidence will reach about 0.6 m at the end of production period. KEYWORDS: Subsidence, South Pars, reservoir rock, semi-analytical method

INTRODUCTION Withdrawal of subsurface fluids such as groundwater, oil, and gas is a major cause for ground

subsidence in the recent decades. Physically, the surface subsidence of hydrocarbon field which is caused by compaction of reservoir rocks is due to the reduction of fluid pore pressure and increase of effective stress. The Ekofisk field is one of the well-known examples of the subsided hydrocarbon fields. In 1984 the seabed under the operational platform had subsided over 3 m, and remediation operation cost approaches one billion dollar (Sulak 1991). At the end of 2000 subsidence of Ekofisk reached to 6.7 m and was continuously subsiding at a fairly constant rate (Hermansen et al. 2000) of about 0.4 m/year. The other well-known example of oil field subsidence is the Wilmington oil field in California, which has experienced 9 meters of subsidence (Mayuga and Allen 1969). The annual rate of surface subsidence in the Wilmington field was up to 70 cm/year (Gurevich and Chilingarian 1995). Reservoir compaction and field

Vol. 18 [2013], Bund. M 2622 surface subsidence also can cause formation and expansion of fractures in the caprock. This may impair the caprock's reliability and provide some paths for the leakage of gas (Gurevich and Chilingarian 1995). Thus, due to the great effects of reservoir compaction and resultant subsidence on the field exploitation, evaluation of this phenomenon is extremely necessary and highly recommended. In order to predict the subsidence above a hydrocarbon field, at the first, the reservoir compaction should be estimated. If the amount of the compaction is notable, (larger than 10 cm) then, the effect of reservoir compaction should be modeled on the field surface (Geertsma 1973). The amount of reservoir compaction is dependent on the thickness of the reservoir, the pressure drop in the reservoir, and the unaxial compaction coefficient of the reservoir rock. The unaxial compaction coefficient can be calculated based on the Hookes law and the poroelastic theory. The unaxial compaction coefficient can also be estimated by the properties of reservoir, such as: lithology, depth of buried, porosity and degree of consolidation (Geertsma 1973).

Presently, various methods have been presented for prediction of subsidence at ground surface. The analytical solutions that are described by Geertsma (1973) can be introduced as first method for subsidence prediction in the hydrocarbon fields. Fokker and Orlic (2006) presented a forward model for subsidence prediction caused by extraction of hydrocarbons. In this model, so called semi-analytical, used the combinations of analytic solutions for solving the visco-elastic equations. The semi-analytic method is applicable for modeling of multilayer subsurface, with visco-elastic parameters changing per layer (Fokker 2002; Fokker and Orlic 2006). In this paper the Semi-analysis (Fokker and Orlic 2006) have been applied to predict subsidence due to hydrocarbon production in the South Pars Gas field.

Geological Setting The South Pars/North Dome gas field in the Persian Gulf is the largest offshore field in the

world and is located at 105 km southwest of the Asalouyeh port of Iran at 52 to 52.5E and 26.5 to 27 N. The area of this field is 9700 km2, and the South Pars, which is part of Iran territory, is 3700 km2 and the rest, North Dome, belongs to Qatar (Figure 1).

Figure 1: Geographical location of the South Pars/North Dome gas field

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The South Pars/North Dome gas field is part of the huge NNESSW trend of Qatar Arch structural feature. The Kangan Formation and the Upper Dalan Member collectively formed South Pars Reservoir. The Kangan and Dalan Formations together are equivalent to the Khuff Formation in Arabian nomenclature. Kangan and Dalan Formations are separated by an impermeable layer. Each formation is divided and separated into two different reservoir layers, by impermeable barriers. Therefore, the field consists of four independent reservoir layers: K1, K2, K3, and K4 (Rahimpour-Bonab 2007). The rocks of the reservoir are mostly carbonates like dolomite, limestone, recrystallized limestone and replacive dolomite. The carbonate rocks of the reservoir, based on Dunham (1962) classification, can be classified as mudstone, grainstone and packstone.

Evaluation of Subsidence Potential According to Geertsma (1973) a field can undergoe noticeable subsidence when one or

several of following conditions are present:

The reservoir rock must be highly compressible.

The reservoir pressure drop must be significant.

The reservoir must have a considerable thickness.

The reservoir must have considerable areal extent compared with reservoir depth.

Determinations of the last three conditions are relatively simple and do not need complex laboratory experimental data. Thus, one of the preliminary steps for evaluation of the subsidence potential for a field is determination of these three conditions, but Geertsma (1973) did not present any definite limits for presence or absence of these conditions in a field. For a better understanding of the south Pars gas field condition, its characteristics were compared with the Ekofisk field, which is shown in Table 1.

Table 1: Characteristic of the South Pars and the Ekofisk Fields

Field Reservoir thickness (m) Initial pressure

(MPa) Abundant

pressure (MPa) Ratio of radius to

depth South Pars 338/3 36.5 6.2 > 9

Ekofisk 300 49.1 - 2.3-3.3

As is shown, there are many similarities between these two fields. The both fields have carbonate reservoirs. The ratio of radius to depth in the South Pars field is significantly larger than the Ekofisk that increase subsidence potential in the South Pars field.

Reservoir Compaction Because of the decreases of reservoir pore pressure due to gas and oil extraction and constant

overburden pressure, the effective stress on the rock structure of the reservoir gradually increases (Ketelaar 2009). In studies related to reservoir compaction, usually the media are assumed linear poroelastic, and composed of isotropic rocks in which the deformation can be expressed by Hookes law (Fjr et al. 2008). The uniaxial reservoir compaction model that was described by Geertsma (1973) is the base on the reservoir compaction calculation. Based on this model, the reduction in the reservoir thickness or its compaction can be calculated as:

PCmhh

V (1)

Vol. 18 [2013], Bund. M 2624 where h is change in height of reservoir, h is the original height of reservoir, P is pressure reduction, is Biots coefficient, and Cm is uniaxial compaction coefficient. The uniaxial compaction coefficient describes the compaction of unit thickness of reservoir per unit change in pore pressure (in MPa 1) that can be calculated based on elastic modulus of reservoir rock as below:

i

ii

iECm

1

2111 (2)

where Ei is Youngs modulus and i is Poissons ratio. Six main reservoir rock types with different elastic properties were identified in the South

Pars reservoir. Some mechanical properties of these rock layers such as the uniaxial compaction coefficient (Cm) and predicted changes of thickness of each layer at the end of extraction period are presented in Table 2.

Table 2: Characteristics of the reservoir rock layers and predicted changes of thicknesses at the end of extraction

Main reservoir rock layers

Cm (MPa-1)

h (m)

L1 0.89 0. 00107 0.043 L2 0.83 0. 00024 0.087 L3 0.82 0. 00031 0.04 L4 0.85 0. 0013 0.201 L5 0.93 0. 00074 0.101 L6 0.87 0. 00038 0.026

To compare, the uniaxial compaction coefficient Cm of the Groningen reservoir varies between 0.45 and 0.75104 MPa-1. The initial pressure in the Groningen reservoir was 34.7 MPa, which has dropped to 12.5 MPa in 2005. Average thickness of the reservoir is 170 m. Therefore, total reservoir compaction between 17 and 28 cm (Ketelaar 2009). The maximum subsidence in the Groningen gas field was reached over 25 cm in 2005.

Field Surface Subsidence After determining the high probability of subsidence in the South Pars gas field, the semi-

analytical method presented by Fokker and Orlic (2006), which was implemented in the AEsubs software, was used for prediction of subsidence in the South Pars gas field. The main advantage of this method, compared with the analytical methods, is its higher accuracy and flexibility for complex conditions of reservoir and overburden. The semi-analytical method, can model several layer media with different characteristics. This method is much simpler and needs less time than numerical method. The plan and profile of subsidence bowl, calculated by AEsubs software are presented in Figures 2a and b, respectively.

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Figure 2: (A) The plan of the subsidence bowl (B) Profile of the subsidence bowl along A-A line calculated by the AEsubs software

In addition to predicted displacement along Z axis, displacements along X and Y axes are presented in the Figure 2b.

The important point in the modeling results is that, the amount of subsidence of reservoir surface is larger than the reservoir compaction. The total compaction in the reservoir was estimated about 0.5 m (Table 2), while the maximum predicted subsidence is about 0.65m. According to Geertsma (1973) this difference can be due to downward displacement of the reservoir bottom. The vertical displacements of the reservoir bottom was modeled by use of the AEsubs software and presented in Figure 3.

A

B

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Figure 3: The vertical displacement of the reservoir bottom modeled by the AEsubs software

CONCLUSIONS The initial pressure in the South Pars gas reservoir was 36.5 MPa, which will dropped to 6.2

MPa at the end of production period. As a result of this pressure decrease, the reservoir will be compacted about 0.5 m. Based on modeling results the maximum surface subsidence in the South Pars filed at the end of production period will reach to 0.65 meters. The results of subsidence modeling indicated that due to downward displacement of the reservoir bottom the predicted amount of subsidence in this field is higher than the amount of the reservoir compaction. The modeling shows that the bottom of reservoir will displace about 0.19 m. For further determination of reservoir compaction, it is suggested that, in addition to performing laboratory tests on core samples, the compaction be measured with use of radio-active bullets that can be shot in the formation at observation wells. It is also suggested that, in order to obtain a complete insight of the Subsidence/Compaction behavior of the South Pars gas field, surface deformation be monitored periodically. It should be noted that, the compaction and/or the subsidence occurs with some delay with respect to change in the reservoir pore pressure (Hettema et al. 2002). Therefore the field surface subsidence may be started several years, ranging from 1.6 to 13 years (Hettema et al. 2002), after the gas production began and will continue several years after the end of production.

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3. Fokker, P. and B. Orlic (2006) Semi-Analytic Modelling of Subsidence, Mathematical Geology, 38(5), 565-589.

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