- Email: [email protected]
Petroleum source-rock potential of the Piranj oil field, Zagros basin
Marine and Petroleum Geology 78 (2016) 448e454
Contents lists available at ScienceDirect
Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
Research paper
Petroleum source-rock potential of the Piranj oil field, Zagros basin Sadegh Elyasi University Student of UNSW, NSW, Australia
a r t i c l e i n f o
a b s t r a c t
Article history: Received 20 October 2014 Received in revised form 8 August 2016 Accepted 26 September 2016 Available online 3 October 2016
Zagros basin constitutes one of the most prolific hydrocarbon producing habitats and the second largest basin in the Middle East. The Piranj oil field is part of The Middle CretaceouseEarly Miocene Petroleum System in Zagros basin and southwest of Iran. This study mainly focuses on organic matter characterization and thermal history of two potential source rock's name Gurpi and Pabdeh formations. To evaluate the candidate source rocks, 50 cuttings and core samples of these rock units from well M-11 (the only well drilled up to the probable source rocks) were analysed, using Rock-Eval pyrolysis and organic petrography. In addition, 1D basin modelling and reconstruction of burial history were applied to analyse the thermal history of these source rocks. The green shale, limestone and marls of Pabdeh formation with average 2.52%wt Total Organic Matter (TOC) and Hydrogen Index (HI) higher than 250 is more favourite source rock in comparison with dark shale and limestone of Gurpi formation by 1.8%wt and HI < 300. Moreover, Pabdeh formation can be classified generally as fair to very good source rocks, with kerogens of type II, while Gurpi formation contain mostly kerogens of type II/III. The average values of Vitrinite reflectance (VR) (from 0.44% to 1.23%) indicate that samples from the well M-11 have reached maturities corresponding to early to peak oil generation. Reconstruction of the thermal history suggests various steady heat flow values (53e91 mW/m2) resulted in the best fit between the observed and the calculated bottom hole temperatures (BHT) and Vitrinite reflectance (VR) in the model. Rock-Eval pyrolysis results and Vitrinite reflectance (VR) suggest that the most of samples are in the early mature to mature stage of hydrocarbon generation. Furthermore, according to the modelling results, petroleum generation from the studied source rocks has began after deposition of related seal-rocks and formation of traps which ensures entrapment and preservation of migrated hydrocarbon. © 2016 Elsevier Ltd. All rights reserved.
Keywords: Geochemical analysis Source rock evaluation Thermal maturity Source rock characterization
1. Introduction The Piranj oil field lies in the southern part of Lorestan Province and the north-western part of Khuzestan Province (SW Iran). The oil-field trends NWeSE and is 98 km long and 5e12 km wide. The oil field's total area is approximately 350 km2 (Fig. 1). The first geologic survey of the basin was conducted in 1997, but extensive exploration and development of this basin did not begin until 2000. In 2000, the first well was conducted to a depth of 2200 m, and the first economic testing was performed in 2005. A total of four wells (exploration and development) were drilled from time period of 2000e2004, and two of them were tested to yield commercial oil flow. However, only one well (M-11) drilled to the source rocks, and one failed to reach to any petroleum (M-5). Drilling reports show that a great part of the oils, variously reservoired in Asmari
E-mail address: [email protected]. http://dx.doi.org/10.1016/j.marpetgeo.2016.09.028 0264-8172/© 2016 Elsevier Ltd. All rights reserved.
formation (Aali, 2006; Haji zadeh, 2002). Although most of the drilled wells discovered oil in the Asmari Formation, there is doubt about the sources of this basin. Many believe that the Pabdeh Formation is the only major source of this basin (Bidehi and Ghaderi, 2001), but several experts argue that the Gurpi Formation can be a possible source-rock too (Agha-Khani and Heydary, 2003). However, all of those hypotheses are based on outcrops of beds. The primary objective of this study is to identify the main source rock(s) and estimate the source rock potential of the basin by evaluating the characteristics of organic matter (OM) through various types of geochemical analyses.
2. Geological background The Piranj petroleum system is deposited and accumulated on a carbonate platform developed across the Zagros Basin (Fig. 1). The Zagros Basin, with an area of 553,000 km2is the second largest basin in the Middle East (Berberian and king, 1995; Szabo and
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
449
Fig. 1. (A) General structural provinces of Iran, (B) six major tectonostratigraphic domains of the Zagros Basin and geographical location of understudy oil-field (C) location of understudy field and sample, (D) Lithology Schematic stratigraphic section showing the Asmari Formation within the Cenozoic rocks of the Zagros Basin.
Kheradpir, 1978). This basin extends from Turkey, north-eastern Syria and north-eastern Iraq through north-western Iran and continues into south-eastern Iran (Jafari, 2007). The geological history of the Piranj includes long time subsidence and deposition interrupted by short time uplift. The folding process of the Zagros basin occurred in the Miocene and Pliocene and continued until the present, which formed long anticlines and most of the oil fields, as well as the understudy oil field, in this basin (Mottie, 1995). According to Motiei (1994) classification, the Zagros Fold-Thrust Belt has been divided into the 3 different tectonic stratigraphic zones, which, from NW to SE, are:
1) Western Zagros or the Lurestan Province 2) Central Zagros or the Izeh Zone and Dezful Embayment 3) and Eastern Zagros or the Fars Province (Fig. 1). The majority of previous studies (Alavi, 2004; Ziba-neshan, 2002) as well as drilling records revealed that the petroleum system in this oilfield contains 4 main formations namely: 1 Asmari (Oligocene to lowermost Miocene) (reservoir rock) 2 Pabdeh (Upper Palaeocene to lowermost Oligocene) this possible source rock is composed of two parts name downer pabdeh (also known as purple shale) and upper pabdeh
450
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
3 Gurpi (Upper Cretaceous; Santonian to Maastrichtian) (possible source rock) 4 Ghachsaran (lower Miocene) (cap rock) (Fig. 1)
3. Sample and method Rock-Eval pyrolysis is a quick, well appreciated and widely used method for geochemical investigation and screening the petroleum generation potential in sedimentary rocks (Horvath et al., 1986; Hurter and Pollack, 1995; Petmecky, 1999; Liu, 2003; Liu and Lee, 2004; Younes, 2005). Since, the source rock potential was evaluated by measuring the amount and the volume of hydrocarbons generated through thermal cracking of the contained kerogen by the Rock-Eval6 pyrolysis instrument. A total of 50 samples (including cutting and core samples) from Gurpi and Pabdeh formations were selected (taken from well M-11)
over the studied oil field. Initially, the selected samples were decontaminated from micas (parts of micas usually come from lost circulation materials) and Iron filings (that come from drill bit). Then the samples were washed with water and detergent several times (until no oil was visible on their surface) to erase and eliminate contaminates from drilling mud additives. Finally, the samples were crushed, pulverized, homogenized and washed with dichloromethane solvent. Pyrolysis experiments were performed using a Rock eEval 6 apparatus manufactured by Vinci technolo gies. Additional details of this method can be found in Espitalie et al. (1977), Tissot and Welte (1984), and Peters et al. (2005). The analysis yield several measured parameters including S1 (mg HC/g rock),S2 (mg HC/g rock), S3 (mg HC/g rock), Total Organic Carbon (TOC) (wt %) and Tmax ( C) (Table 1). Moreover, the hydrogen index (HI), oxygen index (OI), migration index (MI), and production index har et al. (PI) were calculated using the method described by Be (2001).
Table 1 Results of Rock-Eval pyrolysis and Vitrinite Reflectance (Ro%). Formation
Depth (M)
S1
TOC (wt%)
HI
OI
Tmax ( C)
PI
MI(S1/TOC)
Ro %
Pabdeh
2241 2257 2279 2304 2319 2347 2366 2381 2399 2421 2444 2478 2489 2518 2537 2577 2589 2612 2636 2677 2681 2693
1.52 1.81 0.79 1.64 2.24 0.55 1.16 1.12 1.4 0.78 1.42 6.3 1.4 0.72 0.47 1.11 1.14 0.67 9.38 0.47 11.39 9.3
3.37 3.47 1.3 4.82 4.55 0.62 2.21 2.9 3.48 0.94 3.16 2.2 2.42 1.61 1.72 2.67 3.25 0.65 3.08 1.35 2.6 3.13
422 479 172 438 558 156 199 518 385 370 462 325 375 214 205 426 478 287 258 184 289 271
67 50 155 37 74 77 115 64 51 145 46 32 74 81 87 44 53 68 18 72 26 19
425 427 428 426 436 433 431 431 434 432 432 440 443 434 428 442 437 441 438 434 427 440
0.1 0.1 0.26 0.07 0.08 0.43 0.21 0.07 0.09 0.18 0.09 0.47 0.13 0.17 0.12 0.09 0.07 0.27 0.54 0.16 0.6 0.52
0.45 0.52 0.61 0.34 0.49 0.89 0.52 0.39 0.40 0.83 0.45 2.86 0.58 0.45 0.27 0.42 0.35 1.03 3.05 0.35 4.38 2.97
0.44 0.46 0.47 0.46 0.49 0.51 0.52 0.55 0.53 0.54 0.55 0.57 0.58 0.6 0.59 0.62 0.64 0.63 0.66 0.67 0.68 0.71
Gurpi
2706 2719 2744 2763 2791 2809 2825 2839 2858 2877 2909 2922 2946 2953 2973 2996 3015 3048 3078 3093 3111 3136 3147 3155 3167 3188 3197 3213
2.86 1.55 0.58 0.28 1.52 1.33 2.15 1.22 1.44 0.75 1.49 1.54 0.65 0.92 1.2 1.78 2.4 2.08 11.07 10.14 8.12 11.63 8.54 10.2 11.99 1.17 11.46 11.04
3.8 1.76 1.18 0.8 1.23 1.7 2.26 1.42 2.21 1.11 1.38 1.29 0.74 0.99 1.75 0.92 2.15 1.68 2.43 2.27 1.6 2.83 2.81 2.09 2.44 1.46 2.11 1.88
225 277 244 123 292 230 290 265 389 222 384 281 337 334 322 311 94 384 302 408 219 467 442 309 351 319 414 164
39 149 194 110 152 111 67 157 96 179 74 181 110 76 87 199 102 96 54 44 25 52 54 79 61 142 54 67
422 432 426 423 428 424 437 431 429 429 433 426 433 436 436 442 430 435 444 438 441 442 443 446 447 433 445 445
0.09 0.19 0.09 0.17 0.24 0.19 0.2 0.19 0.12 0.17 0.18 0.24 0.17 0.18 0.14 0.32 0.18 0.2 0.48 0.5 0.62 0.42 0.46 0.55 0.52 0.16 0.45 0.68
0.75 0.88 0.49 0.35 1.24 0.78 0.95 0.86 0.65 0.68 1.08 1.19 0.88 0.93 0.69 1.93 1.12 1.24 4.56 4.47 5.08 4.11 3.04 4.88 4.91 0.80 5.43 5.87
0.53 0.55 0.56 0.55 0.58 0.59 0.6 0.61 0.62 0.61 0.63 0.64 0.64 0.67 0.69 0.69 0.75 0.81 0.84 0.85 0.89 0.87 0.95 0.96 0.98 1.01 1.09 1.23
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
Measurements of Vitrinite reflectance (VR) were accomplished in random mode according to Taylor et al. (1998) on 50 samples and were reported in %Ro. The analyses were carried out with an advanced Zeiss Axioplan II microscope. The measurements were performed with an oil immersion objective with 125 magnification under light reflectance at a wavelength of 546 nm. The results are shown in Fig. 2 and Table 1. Basin modelling is a useful method for investigating thermal history, timing of hydrocarbon generation, the burial progress and thermal evolution of sedimentary basins (Waples, 1994; Whiticar, har et al., 2001; Allen and Allen, 1994; Yalcin et al., 1997; Be 2005). WinBury (1D) modelling software (version 2.7) was used for reconstructing the burial history model with available logs, lithology, cuttings information, beds situation data and temperature data. The heat flow is an important input parameter in basin modelling and frequently difficult to define for the geological past. Since, thermal history models are commonly calibrated against maturity and temperature profiles. Recently, heat flow values in the range of 53e91 mW/m2 shown to be in a good accordance with the Vitrinite reflectance (VR) measurements in the wells located in south western of Iran (Rahmani et al., 2010; Alizadeh et al., 2012; Opera et al., 2013a,b; Mashhadi and Rabbani, 2015). 4. Results and discussion 4.1. TOC and Rock-Eval result 4.1.1. Pabdeh formation The Pabdeh Formation consists of Eocene green shale, limestone and marl, and it has a TOC range between 0.62 and 4.82%wt, shows a wide range of variation (Table 1). The difference of the TOC contents in these rock units is considered to have resulted from the changes of the sedimentary facies or the input of OM. According to Peters and Cassa (1994) classification, these values are consistent with source rocks that may have fair to very good source rock potential. Rock-Eval analysis shows that most of samples taken from Pabdeh formation have hydrogen index (HI) more than 250 mg HC/ g TOC, which indicates a fair to good hydrocarbon generation potential. The productivity index (S1/S1þS2) of these rocks ranges between 0.07 and 0.6. Additionally, Tmax varies from 425 to 443 C indicating that most of the hydrocarbons contained in the sediments are in the early oil window stage. In other world, the thermal maturity level of the selected samples, throughout the analysed section, only reached the early mature stage. Approximately 87% of Pabdeh's samples have migration index (MI) < 1.5 indicating an
451
indigenous nature of the hydrocarbons in the rock samples. In conclusion, according to the Rock-Eval results, it can be claimed that the samples of the Pabdeh Formation are generally favourable for generating a significant amount of hydrocarbon.
4.1.2. Gurpi formation The Maastrichtian dark shale and limestone of the Gurpi Formation have TOC values varying from 0.74 to 3.8 wt%, indicating a less favourable source rock for generating a huge amount of hydrocarbon (in comparison with Pabdeh formation). The productivity index varies from 0.09 to 0.68, with an average of 0.29. The HI values of the drilled section range from 94 to 467 mg HC/ g TOC with an average of 300 mg HC/g TOC. This wide range of variation indicating the presence of type II or III mixture. The oxygen index (OI) values range from 25 to 199 and are 100 on average. Approximately 75% of Gurpi samples have Tmax more than 433 C which, according to Hunt (1996) falls in mature zone. Several samples from Gurpi formation have MI (S1/TOC) values more than 2 indicating that the free hydrocarbons have a contribution or improvement from migrated oil. In summary, the rock-Eval results indicate that the level of thermal maturation of OM in the samples from the Gurpi Formation is in the middle to peak stage of oil the generation zone (Hunt, 1996). In addition, the gurpi formation has less potential for being a favourable source rock, in this oilfield, compared to the Pabdeh formation.
4.2. Type of organic matter (kerogen types) The types of organic matter (OM) play a critical role in quality of the source rock. Modified Van Krevelen diagram (HI vs. Tmax) and Pseudo Van Krevelen diagram (HI vs. OI) can evaluate and interpreted the type of OM present in the source rocks (Van Krevelen, 1961). As can be seen on the HI vs. Tmax (Fig. 3a) most samples of the Pabdeh falls within the early mature zone of type II Kerogens. In contrast, most samples taken from Gurpi mainly plotted in the early to peak mature zone. Fig. 3b shows a plot of the hydrogen index (HI) versus the oxygen index (OI) on a pseudo Van Krevelen diagram for the studied source. This diagram suggests Gurpi samples contain mixed kerogen types IIeIII while Pabdeh samples contain kerogen type II. Mixed kerogen type characterises the mixed environment containing a mixture of continental and marginal marine OM and has the ability to generate oil and gas accumulations (Peters and Moldowan, 1993).
Fig. 2. Cross plots showing R2 between maturity parameters vitrinite reflectance (VR) and Tmax for Pabdeh and Gurpi formations.
452
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
Fig. 3. (B) Hydrogen index (HI) versus oxygen index (OI) of pabdeh and gurpi formation obtained from Piranj oil-field (pseudo van krevelen diagram), (A) diagram of Tmax vs. HI plot of the shale and limestone of gurpi and pabdeh formations obtained from well M-11.
4.3. Thermal maturity According to Grassmann et al. (2005), “vitrinit reflectance is the most reliable maturity parameter for calibrating and measuring thermal maturity of organic matter”. 50 samples were selected for vitrinite reflectance (VR) measurement (Ro) based on standard procedure described by Opera et al. (2013a, b) (Table 1). The measured Vitrinite reflectance (VR) value increases gradually with depth. In addition, mean reflectance of Vitrinite particles in Pabdeh formation ranges from 0.44 to 0.71% Ro. Moreover, the studied samples from the Gurpi formation have Vitrinite reflectance (VR) values between 0.53 and 1.23%Ro and this trend tend to increase with depth (Table 1). These results indicate that both formations have entered or are in the oil window, but the OM in the samples from the Gurpi formation are more mature than the OM in the Pabdeh formation. Plots of Tmax against vitrinite reflectance (VR) (Fig. 2) illustrate a good agreement between the Tmax data and the measured vitrinite reflectance (VR) data for Gurpi (R ¼ 0.614) but are inconsistent for Pabdeh. As stated by Dahl et al. (2004), this may be caused by a mineral matrix effect (MME) or the oxidation of the Vitrinite during deposition and transport. Furthermore, the positive correlation between Tmax ( C) data and measured Vitrinite reflectance (% Ro) is a result of their regular and proper increase with depth. In summary, the Gurpi formation with older age and deeper burial is more thermally mature than the Pabdeh formation.
4.4. Burial history In well M-11, a constant heat flow value of 62 mW/m2 gives the best fit between the measured bottom hole temperature and calculated Vitrinite reflectance (VR). The maximum burial temperature (MBT) was recorded between 125 and 135 C for the Ilam formation. The assumption of various steady heat flow values led to the best match between the mean Vitrinite reflectance values (%Ro) and bottom Hole pressure (BHP) to the generated model. Moreover, measured BHT suggested a geothermal gradient of about 25.5 C/ Km. As reported by Opera et al. (2013a, b), the presence and existence of potential source rocks, the extent and timing of petroleum generation and finally the timing of trap formation are the three
most important factors for the CretaceouseEarly Miocene Petroleum System. Since, in this project, the kinetic parameters reported Bordenave and Hegre (2010) by were applied to determine the timing of oil generation and estimate the Transformation Ratio (TR) from the Gurpi and Pabdeh Formations. The created model (Fig. 4) reveals a continuous sedimentation throughout most of its history, except for the time period between the Upper Cretaceous and Early Tertiary. However, in this model the effects erosion and uplift process throughout the time interval of 65e61 Ma was not included, hence the effects are considered to have an insignificant and negligible impact on the present-day temperature and maturity trends. Reconstruction of burial history (Fig. 4) demonstrates steady subsidence and stable sedimentation during nearly most of the Mesozoic and Cenozoic for the well M-11. Gentle and moderate subsidence is recorded by no major tectonic events (before the main phase of Zagros Folding) other than a short period of instability and unsteadiness at the end of the Cenomanian (Bordenave and Hegre, 2005). Burial history reconstruction and thermal modelling suggest that the Pabdeh formation is at an early mature stage with calculated Vitrinite reflectance of 0.6%Ro and a MBT of approximately 115 C. The onset of the oil window was in Miocene at a depth greater than 2600 m for this formation. Furthermore, a MBT of approximately 120 C and calculated Vitrinite reflectance of 0.75% Ro indicated that the Gurpi formation is at the main oil window. The onset of the oil window (0.55e0.65%Ro) for Gurpi formation was in Miocene. This formation entered the main oil window (>0.71%Ro) Within the late Miocene. It can be concluded that hydrocarbon generation from the studied source rocks, Gurpi and Pabdeh formation, have started after deposition of the seal rock and the formation of traps. To sum up, the Gurpi formation has reached to the oil generation window and it is an active source rock for supplying of reservoirs in the studied oil field. The Pabdeh formation is not sufficiently mature for hydrocarbon generation in this oil field.
5. Conclusions The Piranj oil field belongs to the middle Cretaceous to the early Miocene petroleum system in the south-west of Iran. To evaluate
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
453
Fig. 4. Burial history modelling rebuilt for well M-11 and overlying in the studied localities of Piranj oil field.
and measure the source rocks potential of this oil field, Rock-Eval pyrolysis, optical observation of kerogen, elemental analysis and burial history modelling analyses were conducted. Based on well M-11 (the only well drilled to the source rocks and more), the Gurpi and Pabdeh Formations were introduced as source rock candidates in the piranj oil field. The organic and petro graphic analysis of Pabdeh and Gurpi formations suggests that the average TOC of Pabdeh and Gurpi are 2.52% and 1.8%, respectively, values consistent with having fair to very good source rock potential. The Pabdeh contains Type II, while Kerogens in the Gurpi are mixed II/III. Moreover, Tmax values reveal that the Pabdeh and Gurpi sediments have reached early to mature stage for hydrocarbon generation. The Vitrinite reflectance (VR) shows thermally immature to early mature characteristics for the Pabdeh formation. The Gurpi formation is more thermally mature than the Pabdeh formation in this oil field. The constant heat flow value of 62 mW/m2 gives the best fit between the measured BHT and calculated Vitrinite reflectance (VR) values in the studied well. The results of the burial and thermal modelling indicate that the hydrocarbon generation from the Gurpi formation started in the middle Miocene and the main phase of oil generation was in the late Miocene. Additionally, the Pabdeh formation is in the early stages of oil-window. Due to the higher thermal maturity, the Gurpi formation has a more significant role in charging the Piranj oil field than the pabdeh formation. According to burial history modelling results, the gurpi Formation is situated and placed in the middle to peak of the oil window and the Pabdeh formation is in the early stages of oil window. Since, nearly the main portion of the Piranj oil-field must have been contributed and supplied by the Gurpi Formation, with less amounts of oil generating from the Pabdeh formation. In summary, investigation of the oil generation history of the CretaceouseEarly Miocene Petroleum System in the Piranj oil field reveals that the time of oil generation from source rocks was after the deposition of related cap rocks. Foundation item Supported by SEDITCO (þ98265549174) company.
Acknowledgements The authors want to thank his parent, especially his father for their support and university of new south Wales for their help.
References Aali, J., 2006. Geochemistry and origin of the world's largest gas field from Persian Gulf, Iran. J. PSE 03e16. Agha-Khani, B., Heydary, A.M., 2003. sangemanshaehayemohtameldarmeydanhayenaftiostanelorestan. tosehvaekteshafnaft 48 no,4. Alavi, M., 2004. Regional stratigraphy of the Zagros foldethrust belt of Iran and its proforeland evolution. Am. J. Sci. 304, 1e20. Alizadeh, B., Sarafdokht, H., Rajabi, M., Opera, A., Janbaz, M., 2012. Organic geochemistry and petrography of Kazhdumi (AlbianeCenomanian) and Pabdeh (paleogene) potential sourcerocks in southern part of the Dezful Embayment, Iran. Org. Geochem 49, 36e46. Allen, P.A., Allen, J.R., 2005. Basin Analysis: Principles and Applications. Blackwell, Oxford (549 p). har, F., Beaumont, V., Penteado, H.L., De, B., 2001. Rock-Eval 6 technology: perBe formances and developments. Oil Gas Sci. Technol. 56, 111e134. Berberian, M., king, H., 1995. “Master blind thrust faults hidden under the Zagoros folds”, active basement tectonics and surface morphotectonics. Tectonophysics 241, 193e224. Bidehi, G.H., Ghaderi, K., 2001. shenasaeesangemanshadarmantaghelorestan-khozestanbaestefadehazrokhsarrehha. tosehvaekteshafnaft 25 no.7. Bordenave, M.L., Hegre, J.A., 2005. Influence of tectonics on the entrapment of oil in the Dezful Embayment, Zagros fold belt, Iran. J. Pet. Geol. 28, 339e368. Bordenave, M.L., Hegre, J.A., 2010. Current distribution of oil and gas fields in the Zagros Fold Belt of Iran and contiguous offshore as the result of the petroleum systems. In: Leturmy, P., Robin, C. (Eds.), Tectonic and Stratigraphic Evolution of Zagros and Makran during he MesozoiceCenozoic, vol. 330. Geological Society of London, Special Publication, pp. 291e353. Dahl, B., Bojesen-Koefoed, J., Holm, A., Justwan, H., Rasmussen, E., Thomsen, E., 2004. A new approach to interpreting RockeEval S2 and TOC data for kerogen quality assessment. Org. Geochem. 35, 1461e1477. , J., Laporte, J.L., Madec, M., Marquis, F., Leplat, P., Paulet, J., 1977. Me thode Espitalie risation des roches me res, de leur potential pe trolier et de leur rapide de caracte volution. Revue de l’Institut Français du Pe trole 32, 23e45. degree d’e Grassmann, S., Cramer, B., Delisle, G., Messner, J., 2005. Geological history and petroleum system of the Mittelplate oil field, Northern Germany. Int. J. Earth Sci. 94, 979e989. Haji zadeh, A., 2002. amalkardechahhyehafaridarmeydanenaftipiranj. naftvatoseh 14 no. 3. Horvath, F., Szalay, A., Dovenji, P., Rumpler, J., 1986. Structural and thermal evolution of the pannonian basin. In: Thermal Modelling in Sedimentary Basins, Collection on Colloque at Seminars IFP Exploration Research Conferences. Editions Technip, Paris, pp. 339e358. Hunt, J.M., 1996. Petroleum Geochemistry and Geology. Freeman, New York, p. 743.
454
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
Hurter, S.J., Pollack, H.N., 1995. Effect of the Cretaceous SerraGeral igneous event on Basin, southern Brazil. Basin Res. the temperatures and heat fiow of the Parana 7, 215e220. Jafari, M., 2007. Tarikhezaminshenasihozerosbizagroseazoromiehdokhtar ta khalijefars (Kermanshah, Iran). Liu, L., 2003. Geochemistry of source rocks in the lower tertiary nadu formation, eastern depression of the baise basin, Guangxi Province, China. J. Pet. Sci. Eng. 200401. Liu, L., Lee, Y., 2004. Geochemistry of source rocks in the lower tertiary nadu formation, eastern depression of the baise basin, Guangxi Province, China. J. Pet. Sci. Eng. 41, 135e157. Mashhadi, Z.S., Rabbani, A.R., 2015. Organic geochemistry of crude oils and Cretaceous source rocks in the Iranian sector of the Persian Gulf: an oileoil and oilesource rock correlation study. Int. J. Coal Geol. 146, 118e144. Motiei, H., 1994. Geology of Iran: Stratigraphy of Zagros. Geological Survey of Iran Publication, Tehran, p. 583. Mottie, H., 1995. Geology of Iran; Petroleumgeology of Zagros, vol. 37. Geological Society of Iran publication, 2. 1009 P. Opera, A., Alizadeh, B., Sarafdokht, H., Janbaz, M., Fouladvand, R., Heidarifard, M.H., 2013a. Burial history reconstruction and thermal maturity modeling for the middle cretaceouseearly miocene petroleum System, southern Dezful Embayment, SW Iran. Int. J. Coal Geol. 120, 1e14. Opera, Ali, Sarafdokht, Hashem, Janbaz, Mohadeseh, Fouladvand, Razieh, Heidarifard, Mohamad Hosein, 2013b. Burial history reconstruction and thermal maturity modeling for the middle cretaceouseearly miocene petroleum System, southern Dezful Embayment, SW Iran. Int. J. Coal Geol. 04e15. Peters, K.E., Cassa, M.R., 1994. Applied source rock geochemistry. In: Magoon, L.B., Dow, W.G. (Eds.), The Petroleum System from Source to Trap, vol. 60. AAPG Memoir, pp. 93e120. Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guidedinter-preting Molecular Fossils in Petroleum and Ancient Sediments Prentice-Hall. New Jersey, USA. 363
pp. Peters, K.E., Walters, C.C., Moldowan, J.M., 2005. The Biomarker Guide, Volume 2: Biomarkers and Isotopes in the Petroleum Exploration and Earth History. Cambridge University Press, Cambridge, UK. Petmecky, S., 1999. High thermal maturity in the Lower Saxony Basin: intrusion or deep burial? Tectonophysics 04e30. Rahmani, O., Aali, J., Mohseni, H., Rahimpour-Bonab, H., Zalaghaie, S., 2010. Organic geochemistry of gadvan and kazhdumi formations (cretaceous) in South Pars field, Persian Gulf, Iran. J. Pet. Sci. Eng. 70, 57e66. Szabo, F., Kheradpir, A., 1978. Permian and triassic stratigraphy, zagros basin, SouthWest Iran. J. pet. jeol. 57e82. Taylor, G.H., Teichmüller, M., Davis, A., Diessel, C.F.K., Littke, R., Robert, P., 1998. Magmatic volatiles: isotopic variation C, H and S. In: Valley, J.W. (Ed.), Organic Petrology. Borntraeger, Stuttgart, 704 pp. Tissot, B.P., Welte, D.H., 1984. Petroleum Formation and Occurrence. Springer-Verlag, Berlin, p. 699. Van Krevelen, D.W., 1961. Coal. Elsevier Science, New York, p. 514. Waples, D.W., 1994. Modeling of sedimentary basins and petroleum systems. In: Magoon, L.B., Dow, W.G. (Eds.), The Petroleum System from Source to Trap, vol. 60. APG Memoir, pp. 307e322. Whiticar, M.J., 1994. Correlation of natural gases with their sources. In: Magoon, L.B., Dow, W.G. (Eds.), The Petroleum Systemfrom Source to Trap, vol. 60. AAPG Memoir, Tulsa, pp. 261e283. The American Association of Petroleum Geologists. Yalcin, M.N., Littke, R., Sachsenhofer, R.F., 1997. Thermal history of sedimentary basins. In: Welte, D.H., Horsfield, B., Baker, D.R. (Eds.), Petroleum and Basin Evolution. Springer, Berlin, pp. 71e167. Younes, M.A., 2005. Petroleum geochemistry and potential source rock correlation in the Shushan basin, North Western desert, Egypt. Pet. Sci. Technol. 5e11. Ziba-neshan, A.M., 2002. Barreivashenasaeesystemhayenaftidarhozerosobizagrosbatekkey bar meydanhayenaftidehrolan. Naft. energy 23 no. 14.
Contents lists available at ScienceDirect
Marine and Petroleum Geology journal homepage: www.elsevier.com/locate/marpetgeo
Research paper
Petroleum source-rock potential of the Piranj oil field, Zagros basin Sadegh Elyasi University Student of UNSW, NSW, Australia
a r t i c l e i n f o
a b s t r a c t
Article history: Received 20 October 2014 Received in revised form 8 August 2016 Accepted 26 September 2016 Available online 3 October 2016
Zagros basin constitutes one of the most prolific hydrocarbon producing habitats and the second largest basin in the Middle East. The Piranj oil field is part of The Middle CretaceouseEarly Miocene Petroleum System in Zagros basin and southwest of Iran. This study mainly focuses on organic matter characterization and thermal history of two potential source rock's name Gurpi and Pabdeh formations. To evaluate the candidate source rocks, 50 cuttings and core samples of these rock units from well M-11 (the only well drilled up to the probable source rocks) were analysed, using Rock-Eval pyrolysis and organic petrography. In addition, 1D basin modelling and reconstruction of burial history were applied to analyse the thermal history of these source rocks. The green shale, limestone and marls of Pabdeh formation with average 2.52%wt Total Organic Matter (TOC) and Hydrogen Index (HI) higher than 250 is more favourite source rock in comparison with dark shale and limestone of Gurpi formation by 1.8%wt and HI < 300. Moreover, Pabdeh formation can be classified generally as fair to very good source rocks, with kerogens of type II, while Gurpi formation contain mostly kerogens of type II/III. The average values of Vitrinite reflectance (VR) (from 0.44% to 1.23%) indicate that samples from the well M-11 have reached maturities corresponding to early to peak oil generation. Reconstruction of the thermal history suggests various steady heat flow values (53e91 mW/m2) resulted in the best fit between the observed and the calculated bottom hole temperatures (BHT) and Vitrinite reflectance (VR) in the model. Rock-Eval pyrolysis results and Vitrinite reflectance (VR) suggest that the most of samples are in the early mature to mature stage of hydrocarbon generation. Furthermore, according to the modelling results, petroleum generation from the studied source rocks has began after deposition of related seal-rocks and formation of traps which ensures entrapment and preservation of migrated hydrocarbon. © 2016 Elsevier Ltd. All rights reserved.
Keywords: Geochemical analysis Source rock evaluation Thermal maturity Source rock characterization
1. Introduction The Piranj oil field lies in the southern part of Lorestan Province and the north-western part of Khuzestan Province (SW Iran). The oil-field trends NWeSE and is 98 km long and 5e12 km wide. The oil field's total area is approximately 350 km2 (Fig. 1). The first geologic survey of the basin was conducted in 1997, but extensive exploration and development of this basin did not begin until 2000. In 2000, the first well was conducted to a depth of 2200 m, and the first economic testing was performed in 2005. A total of four wells (exploration and development) were drilled from time period of 2000e2004, and two of them were tested to yield commercial oil flow. However, only one well (M-11) drilled to the source rocks, and one failed to reach to any petroleum (M-5). Drilling reports show that a great part of the oils, variously reservoired in Asmari
E-mail address: [email protected]. http://dx.doi.org/10.1016/j.marpetgeo.2016.09.028 0264-8172/© 2016 Elsevier Ltd. All rights reserved.
formation (Aali, 2006; Haji zadeh, 2002). Although most of the drilled wells discovered oil in the Asmari Formation, there is doubt about the sources of this basin. Many believe that the Pabdeh Formation is the only major source of this basin (Bidehi and Ghaderi, 2001), but several experts argue that the Gurpi Formation can be a possible source-rock too (Agha-Khani and Heydary, 2003). However, all of those hypotheses are based on outcrops of beds. The primary objective of this study is to identify the main source rock(s) and estimate the source rock potential of the basin by evaluating the characteristics of organic matter (OM) through various types of geochemical analyses.
2. Geological background The Piranj petroleum system is deposited and accumulated on a carbonate platform developed across the Zagros Basin (Fig. 1). The Zagros Basin, with an area of 553,000 km2is the second largest basin in the Middle East (Berberian and king, 1995; Szabo and
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
449
Fig. 1. (A) General structural provinces of Iran, (B) six major tectonostratigraphic domains of the Zagros Basin and geographical location of understudy oil-field (C) location of understudy field and sample, (D) Lithology Schematic stratigraphic section showing the Asmari Formation within the Cenozoic rocks of the Zagros Basin.
Kheradpir, 1978). This basin extends from Turkey, north-eastern Syria and north-eastern Iraq through north-western Iran and continues into south-eastern Iran (Jafari, 2007). The geological history of the Piranj includes long time subsidence and deposition interrupted by short time uplift. The folding process of the Zagros basin occurred in the Miocene and Pliocene and continued until the present, which formed long anticlines and most of the oil fields, as well as the understudy oil field, in this basin (Mottie, 1995). According to Motiei (1994) classification, the Zagros Fold-Thrust Belt has been divided into the 3 different tectonic stratigraphic zones, which, from NW to SE, are:
1) Western Zagros or the Lurestan Province 2) Central Zagros or the Izeh Zone and Dezful Embayment 3) and Eastern Zagros or the Fars Province (Fig. 1). The majority of previous studies (Alavi, 2004; Ziba-neshan, 2002) as well as drilling records revealed that the petroleum system in this oilfield contains 4 main formations namely: 1 Asmari (Oligocene to lowermost Miocene) (reservoir rock) 2 Pabdeh (Upper Palaeocene to lowermost Oligocene) this possible source rock is composed of two parts name downer pabdeh (also known as purple shale) and upper pabdeh
450
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
3 Gurpi (Upper Cretaceous; Santonian to Maastrichtian) (possible source rock) 4 Ghachsaran (lower Miocene) (cap rock) (Fig. 1)
3. Sample and method Rock-Eval pyrolysis is a quick, well appreciated and widely used method for geochemical investigation and screening the petroleum generation potential in sedimentary rocks (Horvath et al., 1986; Hurter and Pollack, 1995; Petmecky, 1999; Liu, 2003; Liu and Lee, 2004; Younes, 2005). Since, the source rock potential was evaluated by measuring the amount and the volume of hydrocarbons generated through thermal cracking of the contained kerogen by the Rock-Eval6 pyrolysis instrument. A total of 50 samples (including cutting and core samples) from Gurpi and Pabdeh formations were selected (taken from well M-11)
over the studied oil field. Initially, the selected samples were decontaminated from micas (parts of micas usually come from lost circulation materials) and Iron filings (that come from drill bit). Then the samples were washed with water and detergent several times (until no oil was visible on their surface) to erase and eliminate contaminates from drilling mud additives. Finally, the samples were crushed, pulverized, homogenized and washed with dichloromethane solvent. Pyrolysis experiments were performed using a Rock eEval 6 apparatus manufactured by Vinci technolo gies. Additional details of this method can be found in Espitalie et al. (1977), Tissot and Welte (1984), and Peters et al. (2005). The analysis yield several measured parameters including S1 (mg HC/g rock),S2 (mg HC/g rock), S3 (mg HC/g rock), Total Organic Carbon (TOC) (wt %) and Tmax ( C) (Table 1). Moreover, the hydrogen index (HI), oxygen index (OI), migration index (MI), and production index har et al. (PI) were calculated using the method described by Be (2001).
Table 1 Results of Rock-Eval pyrolysis and Vitrinite Reflectance (Ro%). Formation
Depth (M)
S1
TOC (wt%)
HI
OI
Tmax ( C)
PI
MI(S1/TOC)
Ro %
Pabdeh
2241 2257 2279 2304 2319 2347 2366 2381 2399 2421 2444 2478 2489 2518 2537 2577 2589 2612 2636 2677 2681 2693
1.52 1.81 0.79 1.64 2.24 0.55 1.16 1.12 1.4 0.78 1.42 6.3 1.4 0.72 0.47 1.11 1.14 0.67 9.38 0.47 11.39 9.3
3.37 3.47 1.3 4.82 4.55 0.62 2.21 2.9 3.48 0.94 3.16 2.2 2.42 1.61 1.72 2.67 3.25 0.65 3.08 1.35 2.6 3.13
422 479 172 438 558 156 199 518 385 370 462 325 375 214 205 426 478 287 258 184 289 271
67 50 155 37 74 77 115 64 51 145 46 32 74 81 87 44 53 68 18 72 26 19
425 427 428 426 436 433 431 431 434 432 432 440 443 434 428 442 437 441 438 434 427 440
0.1 0.1 0.26 0.07 0.08 0.43 0.21 0.07 0.09 0.18 0.09 0.47 0.13 0.17 0.12 0.09 0.07 0.27 0.54 0.16 0.6 0.52
0.45 0.52 0.61 0.34 0.49 0.89 0.52 0.39 0.40 0.83 0.45 2.86 0.58 0.45 0.27 0.42 0.35 1.03 3.05 0.35 4.38 2.97
0.44 0.46 0.47 0.46 0.49 0.51 0.52 0.55 0.53 0.54 0.55 0.57 0.58 0.6 0.59 0.62 0.64 0.63 0.66 0.67 0.68 0.71
Gurpi
2706 2719 2744 2763 2791 2809 2825 2839 2858 2877 2909 2922 2946 2953 2973 2996 3015 3048 3078 3093 3111 3136 3147 3155 3167 3188 3197 3213
2.86 1.55 0.58 0.28 1.52 1.33 2.15 1.22 1.44 0.75 1.49 1.54 0.65 0.92 1.2 1.78 2.4 2.08 11.07 10.14 8.12 11.63 8.54 10.2 11.99 1.17 11.46 11.04
3.8 1.76 1.18 0.8 1.23 1.7 2.26 1.42 2.21 1.11 1.38 1.29 0.74 0.99 1.75 0.92 2.15 1.68 2.43 2.27 1.6 2.83 2.81 2.09 2.44 1.46 2.11 1.88
225 277 244 123 292 230 290 265 389 222 384 281 337 334 322 311 94 384 302 408 219 467 442 309 351 319 414 164
39 149 194 110 152 111 67 157 96 179 74 181 110 76 87 199 102 96 54 44 25 52 54 79 61 142 54 67
422 432 426 423 428 424 437 431 429 429 433 426 433 436 436 442 430 435 444 438 441 442 443 446 447 433 445 445
0.09 0.19 0.09 0.17 0.24 0.19 0.2 0.19 0.12 0.17 0.18 0.24 0.17 0.18 0.14 0.32 0.18 0.2 0.48 0.5 0.62 0.42 0.46 0.55 0.52 0.16 0.45 0.68
0.75 0.88 0.49 0.35 1.24 0.78 0.95 0.86 0.65 0.68 1.08 1.19 0.88 0.93 0.69 1.93 1.12 1.24 4.56 4.47 5.08 4.11 3.04 4.88 4.91 0.80 5.43 5.87
0.53 0.55 0.56 0.55 0.58 0.59 0.6 0.61 0.62 0.61 0.63 0.64 0.64 0.67 0.69 0.69 0.75 0.81 0.84 0.85 0.89 0.87 0.95 0.96 0.98 1.01 1.09 1.23
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
Measurements of Vitrinite reflectance (VR) were accomplished in random mode according to Taylor et al. (1998) on 50 samples and were reported in %Ro. The analyses were carried out with an advanced Zeiss Axioplan II microscope. The measurements were performed with an oil immersion objective with 125 magnification under light reflectance at a wavelength of 546 nm. The results are shown in Fig. 2 and Table 1. Basin modelling is a useful method for investigating thermal history, timing of hydrocarbon generation, the burial progress and thermal evolution of sedimentary basins (Waples, 1994; Whiticar, har et al., 2001; Allen and Allen, 1994; Yalcin et al., 1997; Be 2005). WinBury (1D) modelling software (version 2.7) was used for reconstructing the burial history model with available logs, lithology, cuttings information, beds situation data and temperature data. The heat flow is an important input parameter in basin modelling and frequently difficult to define for the geological past. Since, thermal history models are commonly calibrated against maturity and temperature profiles. Recently, heat flow values in the range of 53e91 mW/m2 shown to be in a good accordance with the Vitrinite reflectance (VR) measurements in the wells located in south western of Iran (Rahmani et al., 2010; Alizadeh et al., 2012; Opera et al., 2013a,b; Mashhadi and Rabbani, 2015). 4. Results and discussion 4.1. TOC and Rock-Eval result 4.1.1. Pabdeh formation The Pabdeh Formation consists of Eocene green shale, limestone and marl, and it has a TOC range between 0.62 and 4.82%wt, shows a wide range of variation (Table 1). The difference of the TOC contents in these rock units is considered to have resulted from the changes of the sedimentary facies or the input of OM. According to Peters and Cassa (1994) classification, these values are consistent with source rocks that may have fair to very good source rock potential. Rock-Eval analysis shows that most of samples taken from Pabdeh formation have hydrogen index (HI) more than 250 mg HC/ g TOC, which indicates a fair to good hydrocarbon generation potential. The productivity index (S1/S1þS2) of these rocks ranges between 0.07 and 0.6. Additionally, Tmax varies from 425 to 443 C indicating that most of the hydrocarbons contained in the sediments are in the early oil window stage. In other world, the thermal maturity level of the selected samples, throughout the analysed section, only reached the early mature stage. Approximately 87% of Pabdeh's samples have migration index (MI) < 1.5 indicating an
451
indigenous nature of the hydrocarbons in the rock samples. In conclusion, according to the Rock-Eval results, it can be claimed that the samples of the Pabdeh Formation are generally favourable for generating a significant amount of hydrocarbon.
4.1.2. Gurpi formation The Maastrichtian dark shale and limestone of the Gurpi Formation have TOC values varying from 0.74 to 3.8 wt%, indicating a less favourable source rock for generating a huge amount of hydrocarbon (in comparison with Pabdeh formation). The productivity index varies from 0.09 to 0.68, with an average of 0.29. The HI values of the drilled section range from 94 to 467 mg HC/ g TOC with an average of 300 mg HC/g TOC. This wide range of variation indicating the presence of type II or III mixture. The oxygen index (OI) values range from 25 to 199 and are 100 on average. Approximately 75% of Gurpi samples have Tmax more than 433 C which, according to Hunt (1996) falls in mature zone. Several samples from Gurpi formation have MI (S1/TOC) values more than 2 indicating that the free hydrocarbons have a contribution or improvement from migrated oil. In summary, the rock-Eval results indicate that the level of thermal maturation of OM in the samples from the Gurpi Formation is in the middle to peak stage of oil the generation zone (Hunt, 1996). In addition, the gurpi formation has less potential for being a favourable source rock, in this oilfield, compared to the Pabdeh formation.
4.2. Type of organic matter (kerogen types) The types of organic matter (OM) play a critical role in quality of the source rock. Modified Van Krevelen diagram (HI vs. Tmax) and Pseudo Van Krevelen diagram (HI vs. OI) can evaluate and interpreted the type of OM present in the source rocks (Van Krevelen, 1961). As can be seen on the HI vs. Tmax (Fig. 3a) most samples of the Pabdeh falls within the early mature zone of type II Kerogens. In contrast, most samples taken from Gurpi mainly plotted in the early to peak mature zone. Fig. 3b shows a plot of the hydrogen index (HI) versus the oxygen index (OI) on a pseudo Van Krevelen diagram for the studied source. This diagram suggests Gurpi samples contain mixed kerogen types IIeIII while Pabdeh samples contain kerogen type II. Mixed kerogen type characterises the mixed environment containing a mixture of continental and marginal marine OM and has the ability to generate oil and gas accumulations (Peters and Moldowan, 1993).
Fig. 2. Cross plots showing R2 between maturity parameters vitrinite reflectance (VR) and Tmax for Pabdeh and Gurpi formations.
452
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
Fig. 3. (B) Hydrogen index (HI) versus oxygen index (OI) of pabdeh and gurpi formation obtained from Piranj oil-field (pseudo van krevelen diagram), (A) diagram of Tmax vs. HI plot of the shale and limestone of gurpi and pabdeh formations obtained from well M-11.
4.3. Thermal maturity According to Grassmann et al. (2005), “vitrinit reflectance is the most reliable maturity parameter for calibrating and measuring thermal maturity of organic matter”. 50 samples were selected for vitrinite reflectance (VR) measurement (Ro) based on standard procedure described by Opera et al. (2013a, b) (Table 1). The measured Vitrinite reflectance (VR) value increases gradually with depth. In addition, mean reflectance of Vitrinite particles in Pabdeh formation ranges from 0.44 to 0.71% Ro. Moreover, the studied samples from the Gurpi formation have Vitrinite reflectance (VR) values between 0.53 and 1.23%Ro and this trend tend to increase with depth (Table 1). These results indicate that both formations have entered or are in the oil window, but the OM in the samples from the Gurpi formation are more mature than the OM in the Pabdeh formation. Plots of Tmax against vitrinite reflectance (VR) (Fig. 2) illustrate a good agreement between the Tmax data and the measured vitrinite reflectance (VR) data for Gurpi (R ¼ 0.614) but are inconsistent for Pabdeh. As stated by Dahl et al. (2004), this may be caused by a mineral matrix effect (MME) or the oxidation of the Vitrinite during deposition and transport. Furthermore, the positive correlation between Tmax ( C) data and measured Vitrinite reflectance (% Ro) is a result of their regular and proper increase with depth. In summary, the Gurpi formation with older age and deeper burial is more thermally mature than the Pabdeh formation.
4.4. Burial history In well M-11, a constant heat flow value of 62 mW/m2 gives the best fit between the measured bottom hole temperature and calculated Vitrinite reflectance (VR). The maximum burial temperature (MBT) was recorded between 125 and 135 C for the Ilam formation. The assumption of various steady heat flow values led to the best match between the mean Vitrinite reflectance values (%Ro) and bottom Hole pressure (BHP) to the generated model. Moreover, measured BHT suggested a geothermal gradient of about 25.5 C/ Km. As reported by Opera et al. (2013a, b), the presence and existence of potential source rocks, the extent and timing of petroleum generation and finally the timing of trap formation are the three
most important factors for the CretaceouseEarly Miocene Petroleum System. Since, in this project, the kinetic parameters reported Bordenave and Hegre (2010) by were applied to determine the timing of oil generation and estimate the Transformation Ratio (TR) from the Gurpi and Pabdeh Formations. The created model (Fig. 4) reveals a continuous sedimentation throughout most of its history, except for the time period between the Upper Cretaceous and Early Tertiary. However, in this model the effects erosion and uplift process throughout the time interval of 65e61 Ma was not included, hence the effects are considered to have an insignificant and negligible impact on the present-day temperature and maturity trends. Reconstruction of burial history (Fig. 4) demonstrates steady subsidence and stable sedimentation during nearly most of the Mesozoic and Cenozoic for the well M-11. Gentle and moderate subsidence is recorded by no major tectonic events (before the main phase of Zagros Folding) other than a short period of instability and unsteadiness at the end of the Cenomanian (Bordenave and Hegre, 2005). Burial history reconstruction and thermal modelling suggest that the Pabdeh formation is at an early mature stage with calculated Vitrinite reflectance of 0.6%Ro and a MBT of approximately 115 C. The onset of the oil window was in Miocene at a depth greater than 2600 m for this formation. Furthermore, a MBT of approximately 120 C and calculated Vitrinite reflectance of 0.75% Ro indicated that the Gurpi formation is at the main oil window. The onset of the oil window (0.55e0.65%Ro) for Gurpi formation was in Miocene. This formation entered the main oil window (>0.71%Ro) Within the late Miocene. It can be concluded that hydrocarbon generation from the studied source rocks, Gurpi and Pabdeh formation, have started after deposition of the seal rock and the formation of traps. To sum up, the Gurpi formation has reached to the oil generation window and it is an active source rock for supplying of reservoirs in the studied oil field. The Pabdeh formation is not sufficiently mature for hydrocarbon generation in this oil field.
5. Conclusions The Piranj oil field belongs to the middle Cretaceous to the early Miocene petroleum system in the south-west of Iran. To evaluate
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
453
Fig. 4. Burial history modelling rebuilt for well M-11 and overlying in the studied localities of Piranj oil field.
and measure the source rocks potential of this oil field, Rock-Eval pyrolysis, optical observation of kerogen, elemental analysis and burial history modelling analyses were conducted. Based on well M-11 (the only well drilled to the source rocks and more), the Gurpi and Pabdeh Formations were introduced as source rock candidates in the piranj oil field. The organic and petro graphic analysis of Pabdeh and Gurpi formations suggests that the average TOC of Pabdeh and Gurpi are 2.52% and 1.8%, respectively, values consistent with having fair to very good source rock potential. The Pabdeh contains Type II, while Kerogens in the Gurpi are mixed II/III. Moreover, Tmax values reveal that the Pabdeh and Gurpi sediments have reached early to mature stage for hydrocarbon generation. The Vitrinite reflectance (VR) shows thermally immature to early mature characteristics for the Pabdeh formation. The Gurpi formation is more thermally mature than the Pabdeh formation in this oil field. The constant heat flow value of 62 mW/m2 gives the best fit between the measured BHT and calculated Vitrinite reflectance (VR) values in the studied well. The results of the burial and thermal modelling indicate that the hydrocarbon generation from the Gurpi formation started in the middle Miocene and the main phase of oil generation was in the late Miocene. Additionally, the Pabdeh formation is in the early stages of oil-window. Due to the higher thermal maturity, the Gurpi formation has a more significant role in charging the Piranj oil field than the pabdeh formation. According to burial history modelling results, the gurpi Formation is situated and placed in the middle to peak of the oil window and the Pabdeh formation is in the early stages of oil window. Since, nearly the main portion of the Piranj oil-field must have been contributed and supplied by the Gurpi Formation, with less amounts of oil generating from the Pabdeh formation. In summary, investigation of the oil generation history of the CretaceouseEarly Miocene Petroleum System in the Piranj oil field reveals that the time of oil generation from source rocks was after the deposition of related cap rocks. Foundation item Supported by SEDITCO (þ98265549174) company.
Acknowledgements The authors want to thank his parent, especially his father for their support and university of new south Wales for their help.
References Aali, J., 2006. Geochemistry and origin of the world's largest gas field from Persian Gulf, Iran. J. PSE 03e16. Agha-Khani, B., Heydary, A.M., 2003. sangemanshaehayemohtameldarmeydanhayenaftiostanelorestan. tosehvaekteshafnaft 48 no,4. Alavi, M., 2004. Regional stratigraphy of the Zagros foldethrust belt of Iran and its proforeland evolution. Am. J. Sci. 304, 1e20. Alizadeh, B., Sarafdokht, H., Rajabi, M., Opera, A., Janbaz, M., 2012. Organic geochemistry and petrography of Kazhdumi (AlbianeCenomanian) and Pabdeh (paleogene) potential sourcerocks in southern part of the Dezful Embayment, Iran. Org. Geochem 49, 36e46. Allen, P.A., Allen, J.R., 2005. Basin Analysis: Principles and Applications. Blackwell, Oxford (549 p). har, F., Beaumont, V., Penteado, H.L., De, B., 2001. Rock-Eval 6 technology: perBe formances and developments. Oil Gas Sci. Technol. 56, 111e134. Berberian, M., king, H., 1995. “Master blind thrust faults hidden under the Zagoros folds”, active basement tectonics and surface morphotectonics. Tectonophysics 241, 193e224. Bidehi, G.H., Ghaderi, K., 2001. shenasaeesangemanshadarmantaghelorestan-khozestanbaestefadehazrokhsarrehha. tosehvaekteshafnaft 25 no.7. Bordenave, M.L., Hegre, J.A., 2005. Influence of tectonics on the entrapment of oil in the Dezful Embayment, Zagros fold belt, Iran. J. Pet. Geol. 28, 339e368. Bordenave, M.L., Hegre, J.A., 2010. Current distribution of oil and gas fields in the Zagros Fold Belt of Iran and contiguous offshore as the result of the petroleum systems. In: Leturmy, P., Robin, C. (Eds.), Tectonic and Stratigraphic Evolution of Zagros and Makran during he MesozoiceCenozoic, vol. 330. Geological Society of London, Special Publication, pp. 291e353. Dahl, B., Bojesen-Koefoed, J., Holm, A., Justwan, H., Rasmussen, E., Thomsen, E., 2004. A new approach to interpreting RockeEval S2 and TOC data for kerogen quality assessment. Org. Geochem. 35, 1461e1477. , J., Laporte, J.L., Madec, M., Marquis, F., Leplat, P., Paulet, J., 1977. Me thode Espitalie risation des roches me res, de leur potential pe trolier et de leur rapide de caracte volution. Revue de l’Institut Français du Pe trole 32, 23e45. degree d’e Grassmann, S., Cramer, B., Delisle, G., Messner, J., 2005. Geological history and petroleum system of the Mittelplate oil field, Northern Germany. Int. J. Earth Sci. 94, 979e989. Haji zadeh, A., 2002. amalkardechahhyehafaridarmeydanenaftipiranj. naftvatoseh 14 no. 3. Horvath, F., Szalay, A., Dovenji, P., Rumpler, J., 1986. Structural and thermal evolution of the pannonian basin. In: Thermal Modelling in Sedimentary Basins, Collection on Colloque at Seminars IFP Exploration Research Conferences. Editions Technip, Paris, pp. 339e358. Hunt, J.M., 1996. Petroleum Geochemistry and Geology. Freeman, New York, p. 743.
454
S. Elyasi / Marine and Petroleum Geology 78 (2016) 448e454
Hurter, S.J., Pollack, H.N., 1995. Effect of the Cretaceous SerraGeral igneous event on Basin, southern Brazil. Basin Res. the temperatures and heat fiow of the Parana 7, 215e220. Jafari, M., 2007. Tarikhezaminshenasihozerosbizagroseazoromiehdokhtar ta khalijefars (Kermanshah, Iran). Liu, L., 2003. Geochemistry of source rocks in the lower tertiary nadu formation, eastern depression of the baise basin, Guangxi Province, China. J. Pet. Sci. Eng. 200401. Liu, L., Lee, Y., 2004. Geochemistry of source rocks in the lower tertiary nadu formation, eastern depression of the baise basin, Guangxi Province, China. J. Pet. Sci. Eng. 41, 135e157. Mashhadi, Z.S., Rabbani, A.R., 2015. Organic geochemistry of crude oils and Cretaceous source rocks in the Iranian sector of the Persian Gulf: an oileoil and oilesource rock correlation study. Int. J. Coal Geol. 146, 118e144. Motiei, H., 1994. Geology of Iran: Stratigraphy of Zagros. Geological Survey of Iran Publication, Tehran, p. 583. Mottie, H., 1995. Geology of Iran; Petroleumgeology of Zagros, vol. 37. Geological Society of Iran publication, 2. 1009 P. Opera, A., Alizadeh, B., Sarafdokht, H., Janbaz, M., Fouladvand, R., Heidarifard, M.H., 2013a. Burial history reconstruction and thermal maturity modeling for the middle cretaceouseearly miocene petroleum System, southern Dezful Embayment, SW Iran. Int. J. Coal Geol. 120, 1e14. Opera, Ali, Sarafdokht, Hashem, Janbaz, Mohadeseh, Fouladvand, Razieh, Heidarifard, Mohamad Hosein, 2013b. Burial history reconstruction and thermal maturity modeling for the middle cretaceouseearly miocene petroleum System, southern Dezful Embayment, SW Iran. Int. J. Coal Geol. 04e15. Peters, K.E., Cassa, M.R., 1994. Applied source rock geochemistry. In: Magoon, L.B., Dow, W.G. (Eds.), The Petroleum System from Source to Trap, vol. 60. AAPG Memoir, pp. 93e120. Peters, K.E., Moldowan, J.M., 1993. The Biomarker Guidedinter-preting Molecular Fossils in Petroleum and Ancient Sediments Prentice-Hall. New Jersey, USA. 363
pp. Peters, K.E., Walters, C.C., Moldowan, J.M., 2005. The Biomarker Guide, Volume 2: Biomarkers and Isotopes in the Petroleum Exploration and Earth History. Cambridge University Press, Cambridge, UK. Petmecky, S., 1999. High thermal maturity in the Lower Saxony Basin: intrusion or deep burial? Tectonophysics 04e30. Rahmani, O., Aali, J., Mohseni, H., Rahimpour-Bonab, H., Zalaghaie, S., 2010. Organic geochemistry of gadvan and kazhdumi formations (cretaceous) in South Pars field, Persian Gulf, Iran. J. Pet. Sci. Eng. 70, 57e66. Szabo, F., Kheradpir, A., 1978. Permian and triassic stratigraphy, zagros basin, SouthWest Iran. J. pet. jeol. 57e82. Taylor, G.H., Teichmüller, M., Davis, A., Diessel, C.F.K., Littke, R., Robert, P., 1998. Magmatic volatiles: isotopic variation C, H and S. In: Valley, J.W. (Ed.), Organic Petrology. Borntraeger, Stuttgart, 704 pp. Tissot, B.P., Welte, D.H., 1984. Petroleum Formation and Occurrence. Springer-Verlag, Berlin, p. 699. Van Krevelen, D.W., 1961. Coal. Elsevier Science, New York, p. 514. Waples, D.W., 1994. Modeling of sedimentary basins and petroleum systems. In: Magoon, L.B., Dow, W.G. (Eds.), The Petroleum System from Source to Trap, vol. 60. APG Memoir, pp. 307e322. Whiticar, M.J., 1994. Correlation of natural gases with their sources. In: Magoon, L.B., Dow, W.G. (Eds.), The Petroleum Systemfrom Source to Trap, vol. 60. AAPG Memoir, Tulsa, pp. 261e283. The American Association of Petroleum Geologists. Yalcin, M.N., Littke, R., Sachsenhofer, R.F., 1997. Thermal history of sedimentary basins. In: Welte, D.H., Horsfield, B., Baker, D.R. (Eds.), Petroleum and Basin Evolution. Springer, Berlin, pp. 71e167. Younes, M.A., 2005. Petroleum geochemistry and potential source rock correlation in the Shushan basin, North Western desert, Egypt. Pet. Sci. Technol. 5e11. Ziba-neshan, A.M., 2002. Barreivashenasaeesystemhayenaftidarhozerosobizagrosbatekkey bar meydanhayenaftidehrolan. Naft. energy 23 no. 14.