Natural Gas Properties Analysis of Bangladesh: A Case Study of Titas Gas Field

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1 SUST Journal of Science and Technology, Vol. 16, No.2, 2012; P:26-31 Natural Gas Properties Analysis of Bangladesh: A Case Study of Titas Gas Field (Submitted: April 13, 2011; Accepted for Publication: December 13, 2011) Mohammad Islam Miah and M. Farhad Howladar 1 Dept. of Petroleum and Mining Engineering, Shahjalal University of Science and Technology, Sylhet, Bangladesh 1 Abstract Titas is the largest gas field in Bangladesh and the highest gas producer in the country at present which was discovered in 1962 by Shell Oil Company, Pakistan. In designing gas production, processing, transport and handling systems, a complete knowledge of natural gas properties is crucial. For this reason, a detailed research has been done for the measurement and prediction of hydrocarbon fluid properties. This research shows the reservoir of natural gas properties analysis of Titas gas field from gas composition. Based on the studied composition, it is shown that the Titas gas is a sweet gas. The specific gravity and apparent molecular weight of gas are and , respectively. The gas compressibility factor, super-compressibility factor, real gas density and gas formation volume factor are 0.94, 1.031, 9.48 lb m /ft 3, res ft 3 /scf, respectively. The Isothermal compressibility and viscosity of the gas are per psia and cp at reservoir formation temperature F and pressure 3689 psia. The estimated fluid properties are indicates that reservoir fluid type is semi-dry gas and these results are reliable for reserve estimation and well test analysis. Key Words: Composition, Specific Gravity, Formation Volume Factor, Isothermal Compressibility and Viscosity. 1. Introduction The Titas gas field was discovered by Shell Oil Company, Pakistan in 1962.This field is located (Figure-1) in Brahmanbaria district far from about 96 km E-N-E of Dhaka. The Titas field lies in the south central part of the Surma Basin and on the western margin of the Tripura high. The maximum flank dip to the east is 12 0 and that to the west is 6 0. The dip is much gentler in the north-south direction at 3 0 and indicates stronger compression and uplift. The structure was first mapped by Shell in 1960 with a single fold seismic grid. No faults were observed from the 2D seismic data over the Titas gas field and its vicinity. The stratigraphy of the field is related to the stratigraphy of the Surma Basin and is based on lithological correlation with rocks in the Assam oil fields. The formations that have been reached by wells in the Surma Basin are Dupi-Tila, Tipam, Bokabil and Bhuban Formation. Sediments deposited in the later stages of the Indian Plate collision include the Upper Bhuban and Bokabil units which are overlain by Tipam and Dupi-Tila. The reservoir sands in the area are composed of stacked sands which are divided into three groups A, B and C Sands (Figure-1). The most prolific are those of the Group-A Sands which are the dominated constituent of the reservoirs in the Titas Field [1]. In designing gas production, processing, transport, and handling systems a complete knowledge of petroleum properties is crucial. For this reason, the present research has been performed for the measurement and prediction of hydrocarbon fluid properties. The area of property prediction continues to attract significant attention from researchers who seek to optimize design and control of gas systems [2]. Knowledge of pressure-volume-temperature (PVT) relationships and other physical and chemical properties of gases are essential for prediction and solving problems in natural gas reservoir engineering. The physical properties of a natural gas may be obtained directly either by laboratory measurements or by prediction from the known chemical composition of the gas [3]. The type of the gas is sweet or sour; it can be identified mainly based on non-hydrocarbon gases percentages.

2 Natural Gas Properties Analysis of Bangladesh: A Case Study of Titas Gas Field 27 Drilled wells Gas sand A- Group sand B- Group sand C- Group sand West Eas Figure-1: Sub surface location of Titas field and gas bearing sands (Petrel software, Petrobangla) The properties of natural gases are apparent molecular weight, specific gravity and API gravity of gas, gas compressibility factor, super-compressibility factor, gas density, formation volume factor, isothermal compressibility and viscosity of gas. Interkomp Kanata Management studied about initial gas formation volume factor and viscosity at initial pressure and temperature conditions [4]. The objectives of this study are to identify the type of gas reservoir (sweet or sour) and natural gas properties analysis of Titas gas field. 2. Materials and Methods Brief Out Line about the Gas Composition and Used Different Charts Hydrocarbon molecular weight, pseudo-critical temperature and pressure for each component (Economides, 1994) and gas composition of A-Group sand [5] have been used for fluid properties estimation which is listed in Table-1. Reservoir formation temperature (T rf ) and pressure (P rf ) are F and 3689 psia have been used for reservoir fluid properties analysis of Titas gas field [4]. In the present research to complete the analysis properly, some well recognized charts have been used [6]. Table-1: Gas composition of A-group sand (IKM, 1991b) Gas composition Mole fraction (Y j ) C C C i- C n-c i-c n-c C C N H 2 S CO

3 28 Mohammad Islam Miah and M. Farhad Howladar Methodology of Gas Properties Analysis: How to Calculate the Molecular Weight and Gas Specific Gravity: The Apparent molecular weight (M a ) has been estimated from the product of each gas component (Y j ) and molecular weight (M j ) i.e. M a = Y j* M j [2]. The specific gravity of a gas is defined as the ratio of the density of the gas to the density of dry air with both measured at the same temperature and pressure [7]. The specific gravity (γ g ) is calculated from apparent molecular weight i.e. γ g = M a /28.97 [7]. Process of Estimating Gas Formation Volume Factor and Gas Density: The gas formation volume factor (B g ) is defined as the volume of gas at reservoir conditions required to produce one standard cubic foot of gas at the surface. The gas formation volume factor has been estimated as the following steps [2&7]: Step 1: Calculation the pseudo-critical temperature T pc and pseudo- critical pressure P pc, Step 2: Determination of the pseudo-reduced temperature T pr and pseudo-reduced pressure P pr, Step 3: Estimation of the gas compressibility factor (Z) from Standing and Katz chart [8] in Figure-2, Step 4: Calculation of gas formation volume factor. The real gas density (ρ g ) has been calculated as following equation [2]: ρ g = (PM/ZRT) where R is the universal gas constant. Figure-2: Gas compressibility factor (Z) chart (Standing et al, 1942) Steps of Estimating the Gas Compressibility and Viscosity: Isothermal gas compressibility is defined as the fractional change of volume as pressure is changed at constant temperature which has been calculated as the following steps:

4 Natural Gas Properties Analysis of Bangladesh: A Case Study of Titas Gas Field 29 Step-1: Estimation of the product of C pr (Pseudoreduced compressibility) and T pr from Pseudoreduced compressibilities chart for gases, Step-2: Estimation of C pr and gas isothermal compressibility [7] i.e. C g = (C pr /P pc ). The coefficient of viscosity is a measure of the resistance to flow exerted by a fluid. Usually, viscosity is given in units of centipoise (cp). The viscosity of a mixture of gases (µ g ) has been estimated as the following steps: Step-1: Calculation of the viscosity from chart [9] at 1 atmospheric (atm) pressure in Figure-3. Step-2: To take into account the effect of the presence of non-hydrocarbon gases using Figure-3. Step-3: Estimation of the viscosity of gas at elevated temperature-pressure from chart [9] in Figure-4. Figure-3: Viscosity chart at 1 atmospheric pressure (Carr et al, 1954 and Economides et al, 1994) Figure-4: Viscosity chart at elevated temperature-pressure (Carr et al, 1954 and Economides et al, 1994)

5 30 Mohammad Islam Miah and M. Farhad Howladar 3. Results and Discussions In Titas field, the gas composition of methane (mole fraction) is and H 2 S mole fraction is 0 (zero). Since methane is the predominant component of natural gases above 96% which indicate a sweet gas reservoir [10]. The gas composition is known and Kay s mixing rule has been used to calculate the pseudo-critical temperature & pressure. From the data analysis, a detailed reservoir gas properties results are shown in Table-2, 3 and 4. Table-2: Estimated gas compressibility factor (Z) and Formation volume factor of Titas gas field Reservoir Temperature Reservoir pressure Z-factor Gas formation volume factor, B g ( 0 R) (psia) (Dimensionless) ( res ft 3 /scf) Table-3: Apparent molecular weight and density of gas Specific gravity Molecular weight Real gas density, ρ g (Dimensionless) (Dimensionless) (lb m /ft 3 ) Pseudo-reduced Temperature, T pr (Dimensionless) Table-4: Estimated compressibility and viscosity of natural gases Pseudo-critical Pressure, P pr (psia) Product of C pr & T pr (Dimensionless) Gas compressibility, C g (per psia) Viscosity of gases, µ g (cp) The estimated pseudo-critical temperature and pressure are R and psia, respectively. The apparent molecular weight is The gas specific gravity is and API gravity is The gas Z-factor has been estimated from Standing and Katz chart (Figure-2) of 0.94 for sweet gas reservoir. This chart is generally more reliable for sweet natural gases with minor amounts of non-hydrocarbons such as N 2 and CO 2 [2] and supercompressibility factor is Gas compressibility factor may be changed if it is estimated by others methods and correlations. The estimated real gas density is lb m /ft 3 ( gm/cm 3 ) using universal gas constant (R) of The formation volume factor and expansion factor (1/B g ) are res ft 3 /scf and scf/ft 3 at reservoir formation temperature R and pressure 3689 psia, respectively. The real gas density, formation volume factor and isothermal gas compressibilities mainly depend on reservoir pressure, temperature as well as Z-factor. The Isothermal compressibility has been found of per psia using pseudo-reduced compressibility value ( per psia) and estimated Pseudo-critical pressure. The viscosity of hydrocarbon gases is cp at 1 atmosphere. The viscosity of all gases is cp including the effect of the presence of non-hydrocarbon gases at 1 atmosphere. The viscosity of A-group sand is cp at mentioned reservoir temperature and pressure. The effect of each of the non-hydrocarbon gases is to increase the viscosity of the gas mixture. Gas viscosity decreases with reservoir pressure decreases and vice versa. Viscosity of natural gases depends among reservoir temperature, pressure and gas compositions [7]. During gas production history of Titas gas field, some hydrocarbon liquid as condensate and water is produced [5] at the surface condition. The estimated fluid properties indicate that it is a semi-dry gas reservoir. 4. Conclusions Titas gas field is the largest gas producer in Bangladesh which is a sweet gas reservoir. The reservoir fluid type is semi-dry gas. The gas specific gravity is The gas compressibility factor, real gas density, formation volume factor and gas expansion factor are 0.94, lb m /ft 3, res ft 3 /scf and scf/ft 3, respectively. The Isothermal compressibility and viscosity of the gas are per psia and cp at reservoir formation temperature F and pressure 3689 psia. The estimated fluid properties are reliable and can be used for reserve estimation and well test analysis of Titas gas field.

6 Natural Gas Properties Analysis of Bangladesh: A Case Study of Titas Gas Field 31 Acknowledgement We are very much grateful to Mr. Md. Jakaria, Assistant professor, Department of Petroleum and Mining Engineering, Shahjalal University of Science and Technology, Sylhet and Mr. Mijanur Rahman, Deputy General Manager, Reservoir Engineering Department, BGFCL, Bangladesh, for their constructive criticism and overall advice regarding data processing and interpretation. References [1] Reservoir Management Project (RMP)-2, Titas Geological Study, Petrobangla, Bangladesh, p. 36, (2009). [2] Kumar, S., Gas Production Engineering, Gulf publishing Co. V. 4, Houston, Texas, p. 646, (1987). [3] Ahmed, Tarek, Hydrocarbon Phase Behavior, Volume 7, Gulf Publishing Company, Houston, Texas, p. 423, (1989). [4] Interkomp Kanata Management (IKM), Gas Field Appraisal Project: Reservoir Engineering Report, Titas Gas Field, Petrobangla, Bangladesh, p. 92, (1991b). [5] Interkomp Kanata Management (IKM), Gas Field Appraisal Project: Geological, Geophysical and Petrophysical Report, Titas Gas Field, Petrobangla, Bangladesh, p. 88, (1991a). [6] Economides, J. M. et al., Petroleum Production System, Prentice-Hall PTR, p. 611, (1994). [7] McCain, W. D. Jr., The Properties of Petroleum Fluids, second edition, Penn Well Publishing Co., Tulsa, Oklahoma, p. 548, (1990). [8] Standing, M. B. and Katz, D. L., Density of Natural Gases, Trans., AIME, 146, p , (1942). [9] Carr, N. L., Kobayashi, R. and Burrows, D. B., Viscosity of Hydrocarbon Gases under Pressure, Trans., AIME, 201, p , (1954). [10] Imam, B., Energy Resources of Bangladesh, First Edition, University Grants Commission Publication No. 89, Bangladesh, p. 280, (2005).

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