The Effect of Temperature on Hydrocarbon Types in Bara Oilfield, Niger Delta Basin, Gulf Of Guinea West Africa

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1 International Journal of Science and Technology Volume 4 No. 9, September, 2015 The Effect of Temperature on Hydrocarbon Types in Bara Oilfield, Niger Delta Basin, Gulf Of Guinea West Africa Jonathan O. Omoboh, Prince.S. Momta & Francis T. Beka Department of Geology, University of Port Harcourt, Nigeria ABSTRACT This study tries to evaluate the role that temperature plays in the formation of either oil or gas in the Bara oilfield. Resistivity log was used to delineate hydrocarbon-bearing zones, and compared the existence of both liquid and gaseous hydrocarbon with the distribution of temperature and heat flow in the field. Hydrocarbon type refers to either liquid or gaseous hydrocarbon. Nearly all the hydrocarbon intervals in the studied wells have gas capping the oil. Temperature plays a significant role in the transformation of organic matter into the various types of hydrocarbon. The range of temperature that results in the formation of oil and gas or a mixture of the two has been established to be between 50 o C to 200 o C. The highest temperature of 115 o C is recorded in well 4 which occurs towards the centre of the field where there is high geothermal gradient (up to 1.81 o C/100m), whereas the lowest temperature occurred in well 1 which also has the lowest temperature, lowest geothermal gradient with a corresponding low hydrocarbon presence. The occurrence of good quantity of gas in association with oil in the field suggests that the kerogen type is likely of equal proportion of type II and III which favour the formation of both oil and gas in the field. Key words: Catagenesis, Metagenesis, Temperature, Kerogen, Geothermal Gradient 1. INTRODUCTION Many examples show that petroleum originated over a finite temperature range that can be observed in a natural environment. In exploring for oil and gas in wildcat areas, it is important to know whether, or not, the rocks have passed through this generation stage, and if so, at what depth generation started, peaked and terminated. Such data alone, may not pinpoint the location of economic petroleum since they are affected by migration and trapping. However, it does bracket the depth ranges in which mature source beds occur and thus indicate the most likely subsurface zones in which to prospect for oil and gas (Hunt, 1979). The type of hydrocarbon found in a place has some relationship with the geothermal gradient and temperature of the area, because each hydrocarbon type (oil, gas or condensate), has been known to occur or form at a particular temperature from kerogen (Land, 1967). However, it is pertinent to note that the kerogen type also determines the type of hydrocarbon. The generation of petroleum from organic matter is a rate controlled reaction which is principally dependent on temperature according to the Arrhenius equation: K = Ae -(Ea/Rt) (1) Where k is the reaction rate constant related to change in concentration of parent substance and product. A is the frequency factor. T is the temperature in degrees Kelvin. From the above equation, it is obvious that the rate of hydrocarbon generation from organic matter depends mainly on temperature, since the other parameters are constant. At the catagenetic stage, all the hydrocarbons C 1 through C 40 are formed in larger amount than in other stages. Heavy oil fractions are formed first followed by cracking of these fractions to yield light oil and gases as temperature rises. The generation of gases and cracking of heavy hydrocarbon molecules and bitumen already formed from diagenesis creates localized overpressures that force the hydrocarbons out of the source rocks. In the metagenetic stage, only methane is formed in significant amount with eventual formation of graphite-like molecules from the condensation and polymerization of aromatics. Five wells each with gamma ray, resistivity, temperature, sonic, density and neutron logs were used for the study. The resistivity log is used primarily to identify a hydrocarbon bearing zone. High values of resistivity show the presence of oil or gas. Very low resistivity values indicate the presence of highly conductive fluid which in this case should be water. Gas is suspected where we have very high resistivity values which can be confirmed with the balloon effect created by the integration of neutron and density logs. The various contacts separating each of these fluids are easily identified where we have sharp drop in resistivity. E is the activation energy. R is the gas constant. 430

2 2. STUDY LOCATION The BARA oilfield is located in the western part of the Niger Delta sedimentary basin (figure 1). The oilfield is operated by one of the major oil exploration and production company operating in the Niger Delta, Nigeria. The name Bara oilfield is representative of the real name of the field concealed for proprietary reason. 3. GEOLOGIC SETTING OF THE NIGER DELTA The tectonic history and the evolution of the Niger Delta sedimentary basin have been reported by many workers (Weber and Daukoru, 1975; Short and Stauble, 1967; Whiteman, 1982, Doust and Omatsola, 1990). The basin evolved following the separation of African and South American plates during the Early Cretaceous times. This was followed by the opening of the South Atlantic Ocean and several episodes of transgressions and regressions accounted for the sedimentary fills in both the Cretaceous and Tertiary Southern Nigerian sedimentary basins. The sequence of evolution of the delta started with the continent-continent break up, filling and the folding Santonian event in the Benue Trough, the development and filling of the Anambra basin, and the subsequent development of the Niger Delta resulting from the subsidence that occurred down dip of the Anambra Basin. The delta covers an area extent of about 100,000 km 2 and represents the regressive phase of the third cycle of deposition in the southern Nigeria sedimentary basins, which began during the Paleocene and has continued to the present day. 431

3 The subsurface sedimentary sequences are made up of basically lithofacies of three distinct environments of deposition: continental, transitional and marine. The Benin Formation is the continental unit, comprising of massive continental sands with minor shale streaks and lignite, overlying the Agbada Formation, a sequence of interbedded sand/sandstone and shale occurring in almost equal proportion. The Agbada sandstone forms the reservoirs with huge accumulation of hydrocarbon. The basal shale of the Agbada unit forms part of the source rock, whereas the Akata Formation (marine prodelta shale) underlying the Agbada is believed to be the major source rock. 4. MATERIALS AND METHODOLOGY Five wells (figure 2) each with gamma ray, resistivity, temperature, geothermal gradient, sonic, density and neutron logs were used for this study. The sand and shale sequences in the study area were recognized on well log based on the gamma ray signatures. Increasing gamma ray values to the right beyond API show an environment that is made up of majorly fine grained pelitic rocks such as clay or shale. The minimum gamma ray trend signifies sandy intervals. The type of fluid present in the rock was determined from resistivity logs. This was used to identify the various lithologic units in the field. The geothermal gradient calculated for each depth was performed using the relation: Geothermal gradient = T o formation - T o surface. (2) Depth Where T 0 formation is the measured temperature reading from the logs, and T o surface is the ambient temperature which is taken to be 25 o c, since the area lies in the tropics. The depth is the depth of measurement of temperature. The oil kitchen threshold temperature for each well and the depth to top and floor of oil kitchen was determined using the Pigott, 1985 model. Age of the source rock (55.8 million years, Short and Stauble, 1967) was inputted into the model to realize the values for the oil kitchen threshold temperature. The occurrence of gas in the reservoirs was detected from the high resistivity values at the top of the hydrocarbon bearing interval. These intervals also show a wider separation between neutron-density logs (balloon shape). 432

4 Figure 2: Base map of the area showing the locations of the wells 5. RESULTS AND DISCUSSION Hydrocarbon Type Hydrocarbon type here refers to either liquid or gaseous hydrocarbon. Nearly all the hydrocarbon intervals in the wells have gas capping the oil. This implies that there is oil and gas mixture in each of the occurrence; some are even more of gas than oil (figures 4 and 5) except well 1 that shows little or no hydrocarbon presence (figure 3). Gas-Oil-Contact and Oil- Water-Contact are delineated simultaneously at 3690m and 3695 in well 4, and well 2 has most of its hydrocarbonbearing reservoirs capped with gas (figure 4). The gasbearing intervals have the highest resistivity values compared with the oil-bearing portion just below the gas portion. The interpretation is predominantly based on resistivity values especially where the neutron density log is not available. Gaseous hydrocarbons have higher resistivity values than liquid types (the higher the density the lower the resistivity). For a reservoir to have gas capping the oil, the oil column must have been saturated with the gas. The occurrence of good quantity of gas in association with oil in the field, suggests that the kerogen type is likely of equal proportion of type II and type III. 433

5 Fabi 01 [TVD] TVD 0.00 GRN RT GEOTHERM TEMP :15339 Figure 3: Well 1 showing little or no hydrocarbon presence 434

6 Fabi 02 [TVD] TVD 0.00 GRN RT TEMP : GEOTH Fabi 04 [TVD] TVD 0.00 GRN RT TEMP : m, 3483m, 3680m 3945m, 4120m, 4235m Figure 5: Well 4 showing GOC and OWC horizons. Note: GOC is Gas-Oil-Contact; OWC Oil-Water-Contact. Figure 4: Well 2 showing multiple intervals with gas cap. 435

7 Temperature Effects on Hydrocarbon Type The highest temperature in the deepest well of the field is 115 o C (figure 6 and 7). This is below the maximum of 150 to 200 o C in the catagenesis stage, where more gas is expected to be produced from kerogen, and also below the top of the initial oil generative window of the Niger Delta (140 o C) (Ejedawe et al,1984), which now should be producing predominantly gaseous hydrocarbon. Figure 6: Well 5 plot of temperature against depth. 436

8 to 200 o C (392 o F). The generation of petroleum from organic matter is a two-step process involving bitumen as an intermediate, that is, kerogen to bitumen to oil and gas plus residue. The generation of petroleum from organic matter is a rate controlled reaction which is principally dependent on temperature according to the Arrhenius equation. At the catagenesis stage, all the hydrocarbons from C1 through C40 are formed in larger amount than in other stages. Heavy oil fractions are formed first followed by cracking of these fractions to yield light oil and gases as temperature rises. Heavy hydrocarbon fractions are expected to be generated at the onset of catagenesis with lighter ones following as temperature increases. The presence of good proportion of gas in association with oil in this lower temperature range of catagenesis shows that the kerogen type may be dominated by type III. This has potential to generate more gas than oil when subjected to the same temperature with other kerogen types, such as types I and II. Geothermal Gradient and Heat flow within the Field Figure 7: Map of 110 o C temperature for wells 2, 3 and 5. Maps of constant temperature variation with depth for the five wells (figure 7) show that the temperature at 78.8 o C was encountered at shallower depth in wells 2 and 4 than in wells 3, 1 and 5. This indicates a higher heat flow in wells 2 and 4 area within the field. This may have contributed immensely to the repeated presence of gas-capping reservoirs in wells 2 and 4. Well 1 did not yield significant gas sand as in the case of wells 2 and 4 (figure 3). Traditionally, geothermal gradient or temperature increases with depth as a result of mantle heat flow transmitted through earth material to the surface where temperature is lower. The quantity of heat transferred to a particular portion of the earth material lying above the mantle should be the same at a particular level within the earth, if the same quantity of heat is transmitted from the mantle and the earth material is homogenous. The difference in the depth of encountering the 78.8 o C, 90.1 o C, and 110 o C isotherms in the five wells shows that there is additional effect to mantle heat flow that is influencing the vertical heat flow in the field. This may be due to a possible hot spot below the position of wells 2 and 4, more heat generation within the sedimentary succession or possible igneous intrusion, a possible fracture below or a cooling effect of meteoric water at the edges of the field or the difference in the thermal conductivity of earth material in the sedimentary succession within the area (Omoboh et al., 2014). The highest average geothermal gradient is noticed in well 4, followed by well 5, 3 and 2, and lowest in well 1 (table 1, figure 8). This confirms that the thermal conductivities of the lithologies within the field are responsible for the increase in geothermal gradient toward the centre. Well 5 occurs towards the southern part of the field and is thus justified for the high shale percentage been on the more marine part of the field. Table 1: Average geothermal gradients of wells. Well number Field average geothermal gradient Average geothermal gradient( o C/100m) 1.74 Catagenesis is the stage where increasing temperature cause kerogen to be converted to bitumen and then bitumen to oil, condensate and gas. Temperature range is from 50 o C (122 o F) 437

9 International Journal of Science and Technology Volume 4 No. 9, September, 2015 Figure 8: Map of geothermal gradient at m for wells 1-5. The low geothermal gradient at the edge of the field may be attributed to cooling effect of the convectional current of meteoric water from the upper portion of the well. The high geothermal gradient of wells 2 and 4 can also be due to internal heat generated within the sedimentary succession in the area (Omoboh et al., 2014). Heat can be generated through radioactivity when there is disintegration of radioactive elements Makhous et al (1997).Exceptional high pressure can also result in increase in temperature since collision between the molecules of the fluid increases hence resulting in increase in heat (Chilingar et al, 2005). The area might also be closer to a possible intrusion within the position of the two wells or a hot spot occurring within the basement lying below the area occupied by the wells with higher geothermal gradient. Depth of Oil Ceiling and Oil Floor Ekweozor and Okoye (1980) shows that the top of the oil kitchen in the Niger Delta basin was located at an average depth of 3375m and 2900m in onshore and offshore wells respectively through the study of Oleanes. They also show that the kerogen of the source rocks were mainly of humic and mixed varieties and are thus prone to the generation of more gas. However, Aikhiombare et al (1984) shows that type II kerogen is the dominant organic matter in the Niger Delta basin, and thus have potential to generate both oil and gas but with more oil than gas. Combining the above two proposals about the kerogen type in the Niger Delta, we can say that both type II and type III kerogen are abundant in the Niger Delta which has capacity to produce both gas and oil. The average top of oil ceiling (top of oil window) in this study is m and the depth to the oil floor (base of oil window) is m giving the thickness of the oil kitchen to be m (tables 2, 3 and 4) (Omoboh et al., 2014). The top of the initial oil generation window in the Niger Delta was set at 140 o C and has moved upward to shallower depth and temperature of about 95 o C due to time effects on potential source rock which expose them to prolong effects of temperature (Edjedawe et al., 1984). This must have resulted in the maturation of some parts of Agbada Formation. 438

10 Table 2: Oil kitchen top, bottom and thickness for the five wells and average for the field Well number Depth of oil ceiling(m) Depth of oil floor (m) Oil kitchen thickness(m) Average thickness of oil kitchen Table 3: Average geothermal gradients, depths of oil ceiling of wells and average depth of oil ceiling in the field Well Number Temperature difference ( o C) Avg. geoth. Grad. ( o C/100m) Doc (m) Average depth of oil ceiling

11 Table 4: Average geothermal gradients, depths of oil floor of wells and average depth of oil floor in the field Well number Temperature difference ( o C) Avg. Geoth. Grad. ( o C/100m) Dof (m) Average depth of oil floor CONCLUSIONS Temperature and geothermal gradient contribute significantly to the type of hydrocarbon encountered in the Bara oilfield. Hydrocarbon accumulations sometimes have a relationship with relative rise in temperature. Wells located towards the centre of the field experience high temperature and heat flow. This area also contains high accumulation of gas coexisting with oil. The kerogen type in the field is dominated by type II and III which favours the formation of both oil and gas. Well 1 has very low geothermal gradient with little or no hydrocarbon presence. Factors inferred to be responsible may be attributed to subsurface structure, migration and possibly the low temperature and heat flow in the area. REFERENCES Chilingar, G. V. Buryakovsky, L. A. Eremenko, N. A. and Gorfunkei, M. V. (2005): Geology and Geochemistry of Oil and Gas. Development in Petroleum Science 52. Elsevier IGB, UK. 391p. Doust, H and E. Omatsola, (1990): Divergent and passive basin of the Niger Delta. AAPG memoir 48: pp Ejedawe, J. E., Lambert Aikhiombare, D.O., and Okorie, C., (1984): Time of hydrocarbon generation and expulsion in the Niger Delta Basin. Bulletin of NAPE volume 01. Pp Ejedawe, J. E., Coker, S. J. L., Lambert Aikhiombare, D.O., Alofe, K.B. and Adoh, F.O., (1984): Evolution of oil generative window and oil and gas occurrence in the Tertiary Niger Delta Basin. AAPG Bulletin vol. 68 (11) pp Hunt, J. M., (1979): Petroleum Geochemistry and Geology. Freeman and Company publisher, 743p. Lambert Aikhionbare, D. O and Ibe, A. C., (1984): Petroleum source bed evaluation of Tertiary delta. Discussion, AAPG Bulletin, volume 68, pp Land, K. K., (1967): Eometamorphism and Oil and Gas in Time and Space. Bulletin of American society of petroleum Geology vol. 51 (6), pp Makhous, M. Galushkin, Yu. I. and Nikolai, L., (1997): Burial history and kinetic modelling for Hydrocarbon Generation, part 1: the Galo Model. AAPG Bulletin vol. 81, No 10, pp Omoboh, J.O, Momta, P.S and Bamigboye, E.O (2014). The significance of temperature and geothermal gradient to hydrocarbon occurrence: case study of Bara oilfield, western Niger delta, Nigeria. Elixir International Journal, Environ. & Forestry 77 (2014) Pigott, J. D., (1985): Assessing Source Maturity in Frontier Basins: Importance of Time, Temperature and Tectonics. AAPG Bulletin vol.69, No 8, pp Short, K. C and Stauble, A.J., (1967): Outline of geology of Niger Delta. AAPG Bulletin volume 51, pp Weber, K. J and Daukoru, E. N., (1975): Petroleum geology of the Niger Delta. Proceeding of the Ninth World petroleum congress, Tokyo volume, pp Weber, K. J., (1971): Sedimentological aspects of oil fields in the Niger Delta. Geologie En Mijnbouw volume 50 (3), pp Whiteman, A. (1982): Niger Delta, Its Petroleum Geology, Resources and Potential. Vol.1 and 2. London, Graham and Trotman Ltd; 176pg. 440