Organic geochemistry, palynofacies and petroleum potential of the Mukalla Formation (late Cretaceous), Block 16, eastern Yemen

Marine and Petroleum Geology 46 (2013) 67e91

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Organic geochemistry, palynofacies and petroleum potential of the Mukalla Formation (late Cretaceous), Block 16, eastern Yemen Abdulwahab S. Alaug a, David J. Batten b, c, *, Abdulghani F. Ahmed a a

Taiz University, Faculty of Applied Sciences, Department of Geology, Taiz 6803, Yemen School of Earth Atmospheric and Environmental Sciences, The University of Manchester, Oxford Road, Manchester M13 9PL, UK c Institute of Geography and Earth Sciences, Aberystwyth University, SY23 3DB, UK b

a r t i c l e i n f o

a b s t r a c t

Article history: Received 19 September 2012 Received in revised form 12 April 2013 Accepted 27 May 2013 Available online 4 June 2013

The late Cretaceous Mukalla Formation of the Mahra Group is present in the subsurface of eastern Yemen. The palynofacies, thermal maturation and hydrocarbon potential of this formation recorded from three exploratory wells in the Qamar Basin are discussed. Two of the wells are in the offshore part of Block 16 and one is in the onshore part. Both organic geochemical and palynofacies analyses indicate that the formation contains oil- and gas-prone kerogen. Rock-Eval pyrolysis and gas chromatography data show a peak thermal maturation stage for organic matter types II/III and III and good conditions for hydrocarbon generation and expulsion. Three major palynofacies types are identified through the succession. These indicate open marine, marginal- to shallow-marine and fluvio-deltaic environments, reflecting multiple marine transgressive and regressive phases during the period of deposition of the formation, which took place in a humid, subtropical to tropical climate. Ó 2013 Elsevier Ltd. All rights reserved.

Keywords: Petroleum potential Palynofacies Palaeoclimate Mukalla Formation Qamar Basin Yemen

1. Introduction Until the late 1980s, little was known about the geology of Yemen apart from the structural elements recognized from surface studies, such as the Hadramawt Arch and Jiza Trough, and the stratigraphic work of Wetzel and Morton during 1948e1950, who surveyed the area between Mukalla in eastern Yemen and the frontier with Oman (Beydoun, 1964) (Fig. 1). Since then, gravity and magnetic surveys carried out by the Technoexport Petroleum Company have provided a subsurface framework for the Mesozoic basins in the former South Yemen (Isaev, 1987). Paul (1990) produced a schematic map of structural units in the southern and eastern parts of Yemen on the basis of unpublished geophysical data. Further studies of Mesozoic basins in Yemen have been carried out by Redfern and Jones (1995) and Ellis et al. (1996), who identified structural highs and lows (horsts and grabens) based on the 1994 geophysical surveys by Simon Petroleum Technology, and Bosence (1997), who analysed the structure of Mesozoic basins from composite seismic sections.

* Corresponding author. School of Earth Atmospheric and Environmental Sciences, The University of Manchester, Oxford Road, Manchester M13 9PL, UK. Tel.: þ44 1970 622605. E-mail addresses: [email protected] (A.S. Alaug), david.batten@ manchester.ac.uk (D.J. Batten). 0264-8172/$ e see front matter Ó 2013 Elsevier Ltd. All rights reserved. http://dx.doi.org/10.1016/j.marpetgeo.2013.05.018

The Mesozoic basins in Yemen include Sana’a, Siham-Ad-Dali’, Sab’atayn, Balhaf, Say’un-Masilah, Jiza and Qamar (Fig. 1). These formed as a result of Late Jurassic rifting between east Africa and western India. The pre-rift sequence in the basins is represented by the Middle Jurassic Kuhlan Formation (Fig. 2). This consists of a basal transgressive unit of poorly sorted coarse-grained fluvial sandstones that fill topographic lows in the peneplaned basement (Beydoun et al., 1998). Overlying it unconformably are platform carbonates of the Shuqra Formation, which accumulated during the CallovianeOxfordian. Two phases of rifting in Yemen are recognised: Kimmeridgiane Berriasian and HauterivianeBarremian (Redfern and Jones, 1995; Ellis et al., 1996; Sharland et al., 2001). The first phase began in the early Kimmeridgian in western Yemen, in the mid-Kimmeridgianeearly Tithonian in the centre of the country, and a little later in the east (Beydoun et al., 1998; As-Saruri et al., 2010). Synrift deposits include thick carbonates and shales of the Madbi Formation (Fig. 2). The organic-rich intervals in this formation have been regarded hitherto as the main source rocks in the Sab’atayn and Masilah hydrocarbon-producing basins (Alaug et al., 2008, 2011; Hakimi et al., 2011a,b). The carbonates and clastics deposited during the later phase of rifting include the Sa’ar and Qishn formations (Fig. 2). In the latest Early Cretaceous, late synrift carbonates were deposited in eastern Yemen (Fartaq Formation of the Mahra Group) while paralic clastics

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Figure 1. A, B, location maps of the research area showing the Qamar Basin and the wells studied (modified after Beydoun et al., 1996; Brannan et al., 1997; Beydoun et al., 1998).

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69

Figure 2. Lithostratigraphic chart for the Qamar Basin and MesozoiceCenozoic petroleum systems of Yemen (modified after Brannan et al., 1997; Beydoun et al., 1998; As-Saruri et al., 2010; Alaug, 2011a).

were deposited in the west. The transition between clastics and carbonates oscillated from west to east in the eastern part of Yemen as a result of sea-level changes, locally modified by remnant rift topography (Bott et al., 1992; Redfern and Jones, 1995; Bosence,

1997; Brannan et al., 1997). A similar west-to-east clastics-to-carbonate transition occurred in the Late Cretaceous, but progradation extended further eastwards into the Jiza and Qamar basins leading to deposition of the upper part of the Mahra Group, which consists

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of the Mukalla, Dabut and Sharwayn formations (Bosence, 1997; Brannan et al., 1997; Beydoun et al., 1998). A Paleocene marine transgression flooded the whole of eastern Yemen, including the Jahi-Mukalla High, resulting in deposition of widespread shallow-marine carbonates of the Umm er Radhuma Formation of the Hadramawt Group. The carbonate shelf conditions passed into lagoonal, sabkha and marine environments during the Eocene; these are represented by the Jiza, Rus and Habshiyah formations of the middle and upper parts of the Hadramawt Group (Fig. 2). A regional unconformity surface separates this group from the overlying Shihr Group, the youngest rock succession in eastern Yemen. Offshore, the Shihr Group was recognized by Beydoun et al. (1998) to include all subsurface lithostratigraphic units that accumulated during the OligoceneeMiocene transgression that preceded rifting and seafloor spreading in the Gulf of Aden and the offshore part of the Qamar Basin (Fantozzi, 1996; Brannan et al., 1997; Beydoun et al., 1998). The Shihr Group subsequently remained emergent while continuing subsidence in the Qamar Basin was accompanied by deposition of synrift carbonates and clastics represented by the Taqah and Sarar formations (Brannan et al.,1997; Beydoun et al.,1998) (Fig. 2). Brannan et al. (1997,1999) discussed in detail the tectono-stratigraphic development of the Qamar Basin on the basis of unpublished subsurface geophysical data acquired by the Nimir Oil Company, and the geological evolution of the Sab’atayn (Marib-Shabwah) Basin. 2. The Qamar Basin The Qamar Basin is an eastewest trending polyphase rift basin with onshore and offshore parts (Fig. 1). It developed during the Late JurassiceEarly Cretaceous as a result of the break-up of southern Gondwana and the separation of India and Madagascar (Beydoun et al., 1996; Bosence, 1997; Brannan et al., 1997; As-Saruri et al., 2010). The last phase of rifting in the basin occurred during the MioceneeHolocene and was associated with the reactivation of rifting in the Gulf of Aden (Fantozzi, 1996; Birse et al., 1997; Bosellini et al., 2001). Since the onset of this rifting in the Middle Miocene the offshore part of the basin has subsided (Brannan et al., 1997). The basin is bounded to the north by the Hadramawt Arch, which separates both the Jiza and Qamar basins from the southern flank of the Rub’ Al-Khali Basin (Fig. 1). The latter extends northwards beyond the border with Saudi Arabia. The late Cretaceous sediments of the Mukalla, Dabut and Sharwayn formations of the upper part of the Mahra Group conformably overlie the lower part of this group, which has not been penetrated by boreholes, and are unconformably overlain by Cenozoic deposits of the Hadramawt Group (Brannan et al., 1997; Beydoun et al., 1998) (Figs. 1 and 2). The thickness of the sedimentary succession reaches about 5.3 km according to the geophysical analysis of Naji and Janardhana (2009) and Naji et al. (2009), but may be up to 10 km (Bosence, 1997) in the deepest part of the basin. The general geology, tectonics and subsurface geology of the Qamar Basin have been considered in just three publications hitherto: Brannan et al. (1997), Naji and Janardhana (2009) and Naji et al. (2009). Petroleum potential, source rock evaluation and palynofacies studies have been carried out only by Alaug (2011a,b). Block 16 occupies the main part of the Qamar Basin. It is thought to contain a thick sedimentary sequence of Jurassic and younger ages but wells have not so far encountered rocks older that the Mukalla Formation (Figs. 1 and 2). Six petroleum exploratory wells were drilled within the confines of the block during the 1980s and 1990s, but only three of these penetrated this formation (Figs. 1 and 3). 3. The Mukalla Formation The Mukalla Formation of the Mahra Group in the Qamar Basin is mostly composed of intercalations of sandstone, shale, calcareous

shale, siltstone, mudstone and coal. We consider these to represent a succession of deltaic and near-shore to offshore marine-shelf conditions. There was a significant input of terrestrial material from western and north-western parts of the basin via a river system that debouched into the shallow- to open-marine environment of the eastern and south-eastern parts (Figs. 1 and 3). The marine sites were deep enough for basinal facies of suboxiceanoxic character to accumulate; we have recorded a mixture of marine palynomorphs (dinoflagellate cysts, acritarchs and linings of foraminiferal tests) and terrestrially derived spores and pollen from these deposits. The formation represents deposition in a continuously subsiding basin during the break-up of southern Gondwana and the separation of India and Madagascar during the late Mesozoic (Brannan et al., 1997). 4. Aims of this paper In this paper, we report a combined organic geochemical and optical microscopic analysis of samples from the Mukalla Formation, which was penetrated by the following three exploratory wells in Block 16 of the Qamar Basin: the Al-Fatk-1 and 16/G-1 offshore wells and the 16/U-1 onshore well (Figs. 1 and 3). Although the sedimentary succession penetrated by two of these wells (16G1 and 16/U-1) has been considered in previous publications (Alaug, 2011a,b), the Mukalla Formation was not subjected to the analyses presented here. These consist of total organic carbon/Rock-Eval pyrolysis and gas chromatography along with measurements of vitrinite reflectance and an examination of acid-resistant sedimentary organic matter in transmitted light in order to determine the degree to which it has been thermally altered. Although aimed primarily at determining the maturation of the organic matter in the formation and its source potential for hydrocarbons, the data obtained also have palaeoenvironmental implications, which are considered in a general way. 5. Material and methods Rock-Eval pyrolysis has been used extensively for oil and gas exploration in sedimentary basins all over the world. It is the most widely used method for determining the amount, type and thermal maturity of organic matter in a rock and its potential and ability to generate oil and/or gas (e.g., Espitalié et al., 1977, 1984). Hence, we provide only a brief résumé of the procedure here. It involves temperature-programmed heating of a small amount of rock (70 mg) or coal (30e50 mg) in an inert atmosphere (helium or nitrogen) in order to generate parameters S1 and S2, both of which are expressed as milligrammes of hydrocarbons per gramme of rock (mg HC/g rock). S1 measures the amount of free hydrocarbons that can be rendered volatile from the rock without cracking the kerogen whereas S2 measures the hydrocarbon yield from cracking of the kerogen (mg HC/g rock). Determination of total organic carbon (TOC), maximum temperature (Tmax) and hydrogen index (HI) lead to conclusions regarding petroleum potential (PP) and production (PI, production index), otherwise known as the transformation ratio. TOC is expressed as the relative dry weight percentage of organic carbon in the sediments (Batten, 1996a,b); it is not a direct measure of the total amount of organic matter. It is generally accepted that for a rock to be a source of hydrocarbons, it must contain sufficient organic matter for significant generation and expulsion for many years; this has been taken as 0.5 wt% TOC for shales and somewhat less, i.e., 0.3 wt% TOC, for carbonates (Batten, 1996b). Our Rock-Eval pyrolysis study was based on core and cuttings samples from the wells noted above: 91 from Al-Fatk-1, 23 from 16/ G-1 and 65 from 16/U-1 (Table 1).

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Table 1 Rock-Eval pyrolysis results for the Mukalla Formation, Qamar Basin. Well

Depth (m)

TOC

S0

S1

S2

PI

HI

Tmax ( C)

PP

16/G-1

3256 3257 3258 3259 3266 3269 3270 3271 3339 3384 3393 3432 3459 3489 3516 3579 3639 3699 3759 3819 3849 3879 3885 Average Max. Min. 2868 2877 2886 2895 2913 2931 2940 2958 2967 2993 2993 2994 2994 3012 3021 3030 3037 3048 3057 3073 3075 3080 3084 3093 3102 3120 3129 3129 3138 3138 3147 3148 3156 3165 3165 3165 3165 3168 3174 3174 3183 3184 3184 3188 3193 3202 3202

7.91 1.72 1.62 3.24 6.97 2.45 20.8 77.6 0.76 0.77 10.4 1.42 1.5 0.95 1.76 0.84 0.9 0.96 0.93 0.85 0.86 0.79 0.71 6.38 77.60 0.71 1.3 1.3 0.8 1.1 0.9 1.3 1.8 5.5 73 77 24 3 78 74 71 47 44 4.1 0.7 36 8.5 0.8 5.8 0.9 2.5 4.9 5.7 56 71 2.9 78 2.3 4.4 5 4.6 5.2 75 1.7 80 2.1 0.9 79 1.6 1.6 2.3 2.7 72

0.12 0.03 0.03 0.02 0.11 0.04 0.18 0.43 0.01 0.02 0.29 0.1 0.15 0.01 0.15 0 0.01 0.01 0.01 0 0 0 0 0.07 0.43 0.00 0 0 0 0 0 0 0 0 0.17 0.14 0.03 0.02 0.06 0.04 0.06 0.1 0.03 0 0 0.09 0 0 0 0 0 0 0 0 0.04 0 0.04 0 0 0 0 0 0.09 0 0.09 0 0 0.04 0 0 0 0 0.28

2.46 0.35 0.39 0.59 1.59 0.62 8.35 47.8 0.06 0.24 1.74 0.27 0.33 0.09 0.34 0.11 0.16 0.09 0.11 0.1 0.12 0.14 0.1 2.88 47.80 0.06 0.12 0.09 0.06 0.1 0.06 0.1 0.15 0.45 19.01 12.06 3.13 1.92 16.46 11.86 11.95 7.46 6.11 0.48 0.11 4.98 0.86 0.32 0.65 0.19 0.26 1.07 0.55 9.91 15.71 0.34 15.03 0.21 0.39 0.68 1.15 0.58 17.25 0.23 24.55 0.22 0.16 16.17 0.21 0.29 0.3 0.36 17.2

24.61 2.86 2.42 6.11 17.66 5.44 66.08 290.1 0.33 0.83 23.41 1.81 1.8 0.56 2.71 0.42 0.53 0.62 0.65 0.46 0.43 0.55 0.33 19.60 290.10 0.33 1.22 1.51 0.69 0.92 0.69 1.29 2.02 11.38 260.23 230.21 83.95 5.26 251.88 261.46 197.13 147.19 131.39 7.75 0.75 133.65 19.43 1.04 9.11 1.02 4.22 7.94 10.71 152.86 196.58 4.46 266.88 2.74 8.08 7.24 11.09 6.28 220.95 1.65 258.5 2.61 0.99 226.66 1.49 2.12 2.4 3.99 191.09

0.09 0.11 0.14 0.09 0.08 0.1 0.11 0.14 0.15 0.22 0.07 0.12 0.14 0.14 0.13 0.21 0.23 0.13 0.14 0.18 0.22 0.2 0.23 0.15 0.23 0.07 0.09 0.06 0.08 0.1 0.08 0.07 0.07 0.04 0.07 0.05 0.04 0.27 0.06 0.06 0.06 0.05 0.04 0.06 0.13 0.04 0.04 0.24 0.07 0.16 0.06 0.12 0.05 0.06 0.07 0.07 0.05 0.07 0.05 0.09 0.09 0.08 0.07 0.12 0.09 0.08 0.14 0.07 0.12 0.12 0.11 0.08 0.08

311.1 166.3 149.4 188.6 253.4 222 317.7 373.8 43.4 107.8 225.1 127.5 120 58.9 154 50 58.9 64.6 69.9 54.1 50 69.6 46.5 142.72 373.80 43.40 94.6 112.7 85.2 82.9 73.4 99.2 109.8 206.2 358 300.1 352.7 177.1 321.7 354.8 276.1 314.2 301.4 189 104.2 370.2 229.1 123.8 156.5 118.6 166.8 160.7 186.6 272 278.4 155.9 344.4 118.6 182.8 145.1 242.1 121 293.4 98.2 323.5 122.5 111.2 286.9 93.1 130.1 106.7 149.4 265.4

442 449 442 445 442 449 443 439 437 450 433 440 441 438 442 430 432 440 433 425 437 437 436 439.22 450.00 425.00 440 441 441 441 441 444 447 445 444 445 444 446 446 444 446 439 442 444 448 449 449 443 447 446 451 449 452 447 442 445 441 451 453 442 448 450 443 447 444 452 448 439 451 454 450 443 451

27.19 3.24 2.84 6.72 19.36 6.1 74.61 338.33 0.4 1.09 25.44 2.18 2.28 0.66 3.2 0.53 0.7 0.72 0.77 0.56 0.55 0.69 0.43 22.55 338.33 0.40 1.22 1.51 0.69 0.92 0.69 1.29 2.02 11.38 260.23 230.21 83.95 5.26 251.88 261.46 197.13 147.19 131.39 7.75 0.75 133.65 19.43 1.04 9.11 1.02 4.22 7.94 10.71 152.86 196.58 4.46 266.88 2.74 8.08 7.24 11.09 6.28 220.95 1.65 258.5 2.61 0.99 226.66 1.49 2.12 2.4 3.99 191.09

16/U-1

(continued on next page)

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Table 1 (continued ) Well

Al-Fakt-1

Depth (m)

TOC

S0

S1

S2

PI

HI

Tmax ( C)

PP

3211 3220 3223 3229 3231 3238 3238 3247 3247 3253 3256 3256 3265 3283 3284 3292 3292 3300 Average Max. Min. 3251 3260 3269 3275 3284 3293 3326 3362 3368 3369 3371 3372 3383 3392 3401 3402 3410 3426 3434 3443 3452 3467 3476 3482 3488 3491 3500 3501 3506 3507 3515 3524 3525 3533 3534 3542 3543 3551 3552 3557 3558 3566 3575 3584 3593 3602 3611 3617 3626 3635 3644 3645 3653 3662

2.7 2.4 1.3 3.4 2.2 1.6 72 4.9 78 6.5 3.4 73 1.5 1.2 1.3 1.9 78 73 23.56 80 0.7 0.41 0.39 0.34 0.35 0.22 0.37 0.57 2 7.06 69.02 4.77 66.55 0.61 0.51 1.34 69.23 3.64 13.7 1.75 1.48 0.55 0.35 0.62 1.18 1.61 0.4 1.82 72.73 6.92 69.95 1.26 0.46 87.4 0.65 84.2 0.64 73.93 0.43 17.87 0.95 87.1 1.66 0.4 0.65 0.98 5.68 0.72 1.91 0.77 2.35 0.97 79.91 3.01 0.5

0 0 0 0 0 0 0.12 0.02 0.19 0.01 0 0.56 0 0 0 0 0.38 0.24 0.04 0.56 0 e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e

0.4 0.33 0.24 0.43 0.32 0.35 20.05 1.04 19.65 1.11 0.96 27.24 0.21 0.14 0.17 0.37 20.34 17.33 5.11 27.24 0.06 0.01 0.02 0.01 0.01 0.02 0.01 0.02 0.20 0.68 11.32 0.50 11.11 0.02 0.03 0.10 13.08 0.34 2.33 0.11 0.14 0.04 0.02 0.05 0.09 0.11 0.01 0.20 12.11 0.63 9.79 0.07 0.01 10.87 0.04 14.70 0.04 11.79 0.04 1.78 0.08 12.37 0.15 0.03 0.07 0.09 0.75 0.07 0.17 0.06 0.31 0.11 10.99 0.39 0.08

3.94 3.35 1.75 5.43 2.87 1.6 226.36 7.56 262.31 10.24 9.71 272.77 1.98 1.75 1.87 2.67 228.73 197.53 70.69 272.77 0.69 0.18 0.22 0.17 0.18 0.20 0.21 0.40 2.44 7.55 226.39 12.40 222.28 0.56 0.52 2.55 218.07 6.77 38.91 3.76 3.60 0.67 0.42 0.79 1.89 2.70 0.32 4.00 242.19 15.71 195.86 1.83 0.43 271.81 0.73 245.02 0.68 235.84 0.66 44.50 1.39 247.36 3.00 0.54 0.84 1.24 18.63 0.75 5.79 0.71 6.13 1.88 219.75 6.50 0.98

0.09 0.09 0.12 0.07 0.1 0.18 0.08 0.12 0.07 0.1 0.09 0.09 0.1 0.07 0.08 0.12 0.08 0.08 0.09 0.27 0.04 0.05 0.08 0.08 0.08 0.08 0.05 0.05 0.08 0.09 0.05 0.04 0.05 0.03 0.05 0.04 0.06 0.05 0.06 0.03 0.04 0.06 0.05 0.06 0.05 0.04 0.03 0.05 0.05 0.04 0.05 0.04 0.02 0.04 0.05 0.06 0.06 0.05 0.06 0.04 0.06 0.05 0.05 0.05 0.08 0.07 0.04 0.09 0.03 0.08 0.05 0.06 0.05 0.06 0.08

143.8 137.3 131.6 161.1 132.3 103.2 313.5 155.9 336.7 158 286.4 374.7 131.1 147.1 141.7 139.1 292.1 272.5 197.30 374.7 73.4 45 56 50 51 91 57 70 122 107 328 260 334 92 102 190 315 186 284 215 243 122 120 127 160 168 80 220 333 227 280 145 93 311 112 291 106 319 153 249 146 284 181 135 129 127 328 104 303 92 261 194 275 216 196

447 448 447 443 451 445 446 445 449 447 442 444 443 444 448 447 446 449 445.94 454 439 448 445 446 447 448 446 450 451 441 438 442 435 450 447 446 433 441 446 441 444 452 451 448 438 445 450 443 440 444 444 446 451 442 452 443 453 442 458 447 451 440 450 457 453 454 448 447 451 452 444 450 446 450 454

3.94 3.35 1.75 5.43 2.87 1.6 226.36 7.56 262.31 10.24 9.71 272.77 1.98 1.75 1.87 2.67 228.73 197.53 70.69 272.77 0.69 0.19 0.24 0.18 0.19 0.22 0.22 0.42 2.64 8.23 237.70 12.90 233.39 0.58 0.55 2.65 231.16 7.11 41.24 3.88 3.74 0.71 0.44 0.83 1.98 2.81 0.33 4.20 254.30 16.34 205.65 1.90 0.44 282.69 0.76 259.72 0.72 247.63 0.70 46.28 1.47 259.73 3.15 0.57 0.91 1.33 19.38 0.82 5.96 0.77 6.44 1.99 230.74 6.89 1.06

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Table 1 (continued ) Well

Depth (m)

TOC

S0

S1

S2

PI

HI

Tmax ( C)

PP

3671 3680 3681 3689 3690 3707 3713 3722 3743 3752 3770 3779 3780 3785 3794 3809 3818 3827 3830 3845 3854 3860 3869 3878 3887 3896 3905 3929 3935 3944 3953 3962 3971 3980 4004 4076 4158 Average Max. Min.

23.6 1.06 75.69 2.12 76.98 0.99 3.61 0.67 1.11 0.82 0.73 1.41 45.44 0.59 0.67 2.21 2.98 0.86 7.18 0.74 1.03 2.65 0.74 1.46 0.46 1.04 0.46 1.22 0.69 0.38 0.75 1.02 0.42 0.75 0.55 0.8 54.42 12.89 87 0.22

e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e e

3.04 0.13 10.22 0.25 12.70 0.14 0.54 0.10 0.14 0.11 0.08 0.19 6.36 0.08 0.09 0.40 0.52 0.09 1.36 0.11 0.17 0.45 0.09 0.21 0.04 0.16 0.05 0.23 0.08 0.05 0.12 0.10 0.04 0.09 0.07 0.05 5.06 1.89 14.7 0.01

23.36 1.59 204.36 4.20 254.03 1.24 10.83 1.12 1.75 1.13 0.66 3.24 127.23 0.94 1.17 5.68 6.47 1.32 27.14 1.08 1.87 6.41 1.10 1.88 0.28 1.04 0.42 1.53 0.59 0.39 0.83 0.86 0.37 0.57 0.50 0.36 84.35 36.38 272 0.17

0.13 0.08 0.05 0.06 0.05 0.11 0.05 0.09 0.08 0.1 0.12 0.06 0.05 0.09 0.08 0.07 0.08 0.07 0.05 0.1 0.09 0.07 0.08 0.11 0.15 0.15 0.11 0.15 0.14 0.13 0.14 0.12 0.12 0.15 0.13 0.13 0.06 0.07 0.2 0.02

99 150 270 198 330 125 300 167 158 138 90 230 280 159 175 257 217 153 378 146 182 242 149 129 61 100 91 125 86 103 111 84 88 76 91 45 155 172.78 378 45.00

448 452 443 451 443 453 449 459 453 456 451 451 446 456 457 451 449 456 434 452 454 448 456 453 464 454 455 458 460 461 458 460 472 455 463 470 469 449.90 472 433.00

26.40 1.72 214.58 4.45 266.74 1.37 11.37 1.22 1.89 1.24 0.74 3.44 133.59 1.02 1.27 6.08 6.98 1.41 28.50 1.19 2.04 6.86 1.19 2.09 0.32 1.20 0.46 1.75 0.68 0.44 0.95 0.96 0.41 0.66 0.57 0.41 89.41 38.27 282.7 0.184

Palynofacies analyses have also been widely applied in the search for hydrocarbons. Our study is based on the acid resistant organic matter recovered from 25 cuttings samples from Al-Fatk1, 61 cuttings and 8 core samples from 16/G-1 and 49 cuttings samples from 16/U-1 (Table 2). The preparation of the samples for examination followed standard procedures, namely digestion in hydrochloric (35%) and hydrofluoric (40%) acids followed by washing until all traces of acidity were removed. The sedimentary organic matter (SOM) recovered was sieved and then mounted on microscope slides in glycerine jelly. None of the organic residues was subjected to oxidation or ultrasonic vibration because some organic particles may be destroyed by such procedures. The palynological slides were examined under a Zeiss Axioskop 40 transmitted light microscope (Serial No. 3310000267) equipped with a Canon Power Shot Camera A640 (Serial No. 2936113214) in the Department of Geology, Taiz University, Yemen. Qualitative and quantitative analyses of the palynomorph associations were based on counts of 200 or more specimens for all of the samples apart from those yielding impoverished assemblages. Several numerical scales based on palynomorph colours and linked to phases of organic maturation and petroleum generation, have been erected since the 1960s, beginning with Correia (1967) and Staplin (1969), whose thermal alteration index (TAI) was developed as a relatively simple and rapid means by which to evaluate kerogen maturation from changes in colour that reflect the thermal and burial history of organic matter. For a discussion of this

and other thermal alteration scales, see Batten (1996b). All are based mainly on thermally induced colour changes in palynomorphs with increasing depth of burial (e.g., Batten, 1980, 1996b; Smith, 1983; Pearson, 1984; Collins, 1990; Peters and Cassa, 1994); hence, it is necessary to examine palynomorph preparations that have not been subjected to oxidative treatment, which might cause partial loss of colour (Table 2). The colour of the unoxidized organic matter under a transmitted light microscope was categorized according to a TAI consisting of a ten-point scale. Measurements for most of the samples examined (Table 2) were based on the smooth-walled Cyathidites/Deltoidospora group of spores and similar forms, and were categorized as follows: 1e3, immature (up to 0.5% Ro: see below), 4e7, mature (0.5e1.7% Ro), more than 7e10, over-mature (2% Ro). Vitrinite reflectance (Ro) and gas chromatographic techniques were standard. Data for both of these procedures were provided by the Yemeni Production and Exploration Petroleum Authority (PEPA) (Tables 3e6). 6. Source rock evaluation High quality source rocks are generally organic-rich, finegrained sediments that are naturally capable of generating and releasing hydrocarbons in sufficient quantities to be commercially viable (Hunt, 1996). The results of our Rock-Eval pyrolysis of 179 core and cuttings samples from the Mukalla Formation from depth intervals 3256e3885 m in the 16/G-1, 2868e3300 m in the 16/U-1

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Table 2 SOM (sedimentary organic matter), palynomorphs and TAI (thermal alteration index) results for the Mukalla Formation. Well

S. No

Depth (m)

Pollen

Spores

Dinocysts

FLT

Algae

Phytoclasts

AOM

Acrit.

Fungi

TAI

16/G-1

1 2 3 4 5 6 7 8 9 13 14 15 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58 59 60 61 62 63 64 65 66 67 68 69 1 2 3 4 5 6 7 8 9

3201 3210 3213 3222 3228 3230 3240 3255 3267.5 3268.8 3270.6 3271.1 3279 3297 3306 3321 3324 3330 3339 3348 3360 3366 3375 3381 3393 3396 3405 3414 3423 3432 3441 3456 3465 3471 3483 3489 3504 3522 3537 3546 3561 3576 3591 3606 3630 3645 3657 3675 3687 3699 3705 3714 3723 3732 3750 3768 3777 3780 3783 3795 3813 3831 3852 3870 3885 2868 2877 2886 2895 2913 2931 2940 2958 2967

40 22 18 13 0 9 12 5 0 7 0 0 15 6 36 0 54 76 11 72 15 20 41 30 10 12 19 37 15 66 81 32 42 19 10 23 22 21 20 30 35 37 36 40 40 45 48 28 10 21 43 20 29 52 23 32 32 31 20 36 30 26 40 49 81 11 12 14 18 15 17 16 22 17

37 3 1 7 0 6 1 0 0 3 0 0 2 0 29 0 27 40 2 31 6 18 40 20 7 8 9 35 8 32 47 17 35 8 10 9 8 7 7 12 16 20 26 25 26 30 36 30 24 31 47 30 42 44 29 44 45 42 10 19 27 14 60 46 30 9 10 13 11 13 15 15 16 13

60 8 3 4 0 13 6 0 0 0 0 0 7 0 22 0 39 61 3 38 6 7 32 33 10 9 7 9 1 62 42 8 28 11 2 5 5 5 4 3 8 11 15 20 19 20 25 9 5 36 64 55 12 21 15 30 13 33 4 8 26 16 30 31 40 0 4 2 2 2 0 0 4 0

68 7 3 1 0 8 1 0 0 0 0 0 1 0 10 0 13 14 8 10 2 1 5 15 16 8 3 3 1 11 6 6 7 0 2 1 1 1 1 2 4 3 2 2 4 5 7 1 3 3 4 12 2 14 8 14 12 5 4 7 6 10 16 9 14 2 6 1 1 4 0 0 4 0

1 1 0 1 0 6 0 0 0 0 0 0 6 0 6 0 7 14 1 12 1 6 6 1 1 4 7 67 38 26 60 20 8 9 2 1 1 1 1 1 0 0 0 0 1 2 2 103 6 4 3 4 2 9 9 12 2 4 2 2 4 4 15 7 8 1 3 8 12 17 12 10 8 11

50 70 90 110 80 60 70 70 0 100 150 20 80 64 100 80 60 80 80 80 80 20 50 40 90 79 75 25 70 47 20 70 30 60 110 91 90 85 85 90 70 70 75 80 70 65 60 40 100 72 60 49 70 60 70 80 110 120 86 75 30 60 60 70 70 120 120 120 120 120 100 110 100 110

40 100 85 62 120 100 110 125 0 90 50 180 120 130 50 120 40 20 95 32 90 126 70 60 66 80 80 23 67 50 48 45 46 93 64 70 73 79 82 60 67 59 46 33 38 31 40 20 50 30 30 30 40 40 42 40 30 40 70 53 69 60 50 20 40 60 50 40 40 30 60 50 50 50

3 0 0 0 0 0 0 0 0 0 0 0 1 0 0 0 2 1 0 3 0 2 8 1 0 0 0 0 0 5 3 1 3 0 0 0 0 1 0 1 0 0 0 0 1 1 2 2 1 1 1 0 2 2 2 2 2 9 4 0 1 1 0 7 4 0 0 2 0 0 0 0 0 0

2 0 0 2 0 0 0 0 0 0 0 0 0 0 0 0 2 3 0 5 0 0 1 0 0 0 0 1 0 1 1 1 1 0 0 0 0 0 0 1 0 0 0 0 1 1 1 1 1 2 8 0 1 1 2 1 2 3 0 0 7 12 0 9 5 0 0 2 0 0 0 0 0 0

5 5 5 5 5 5 5 5 0 5 5 5 5 5 5 5 5 5 5 5 5 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 7 5 5 5 5 5 5 6 6 6

16/U-1

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Table 2 (continued ) Well

Al-Fatk-1

S. No

Depth (m)

Pollen

Spores

Dinocysts

FLT

Algae

11 12 13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32 33 34 35 36 37 38 39 40 41 42 43 44 45 46 47 48 49 1 2 3 4 5 6 7 8 9 10 11 12 13 14 15 16 17 18 19 20 21 22 23 24 25

2990.4 2993.8 2994.1 2994.4 3012 3021 3030 3037 3048 3057 3073 3075 3080 3084 3093 3102 3120 3129 3138 3147 3148 3156 3168 3174 3184 3188 3193 3202 3211 3220 3229 3231 3238 3247 3256 3265 3284 3292 3300 3255 3257 3266 3347 3365 3383 3392 3401 3410 3419 3428 3437 3443 3515 3524 4058 4088 4136 4139 4160 4196 4217 4226 4259 4295

28 27 18 22 16 18 19 11 10 9 7 8 7 11 22 13 15 17 15 11 10 17 14 19 23 16 11 12 16 13 19 18 12 8 15 0 7 5 11 24 21 20 4 20 45 20 31 20 10 10 30 21 50 15 27 0 0 8 6 7 3 3 0 4

18 11 14 17 11 9 15 5 6 7 3 4 3 5 12 11 12 13 12 9 11 12 11 13 16 6 9 8 11 11 9 3 5 3 5 0 6 3 5 15 13 12 0 13 30 5 17 10 2 5 20 12 25 5 15 0 0 2 2 3 0 1 0 0

0 2 2 0 0 0 3 5 0 2 0 3 4 0 6 0 0 3 4 5 0 0 0 7 0 0 0 0 1 3 2 0 8 0 0 0 2 0 2 13 14 3 0 0 0 0 2 0 3 1 15 4 40 0 13 0 0 0 0 3 0 0 0 0

0 0 0 0 0 0 2 3 0 0 0 3 3 0 0 1 0 0 1 2 0 0 1 4 0 0 0 0 0 2 0 0 5 0 0 0 1 1 1 3 7 5 0 7 0 0 10 2 0 0 5 3 5 5 5 0 0 0 0 0 0 0 0 0

6 5 7 12 4 3 2 3 4 2 1 2 3 2 3 1 4 8 1 1 2 3 2 0 2 0 0 3 0 1 0 0 0 2 0 0 4 0 0 0 0 0 0 0 0 0 1 0 0 0 0 0 0 0 0 0 0 0 1 0 0 0 0 0

and 3251e4158 m in the Al-Fatk-1 wells (Fig. 3) are shown in Table 1. 6.1. TOC and petroleum potential The plot of TOC versus S2 shows that most of the samples studied indicate source rocks of fair to excellent quality with

Phytoclasts

AOM

Acrit.

100 120 130 110 100 80 90 100 110 110 120 100 90 80 90 110 100 90 90 80 100 100 110 110 120 110 100 100 90 100 100 110 120 120 100 100 110 110 100 60 55 60 20 90 100 100 90 108 75 74 100 100 60 120 80 30 30 50 80 77 60 50 40 50

50 40 30 40 70 90 70 70 70 70 70 80 90 100 70 70 70 70 80 90 80 70 60 50 40 70 80 80 80 70 70 70 50 70 80 100 70 80 80 90 90 100 176 70 25 75 50 60 110 110 30 60 20 55 60 170 170 140 112 110 147 146 160 146

0 0 0 0 0 0 0 0 0 0 0 0 0 4 0 0 0 0 0 3 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 2 0 1 0 0 0 0 0 0 0 0 0 0 0 0 0 3 0 0 1 0 0 0 0 0 0 0 0

Fungi 0 0 0 4 0 0 0 5 2 1 0 0 0 0 0 0 0 0 0 0 0 0 3 0 0 0 0 0 0 0 0 0 0 0 0 0 0 2 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0 0

TAI 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 6 7 7 7 7 7 7 8 8 8 8 8 8

S2 ranging from 0.3 to 290 and an average value of 20 mg HC/g rock for the 16/G-1 well, 0.7 to 273 and an average value of 71 mg HC/g rock for the 16/U-1 well, and 0.17 to 272 and an average value of 36 mg HC/g rock for the Al-Fatk-1 well (Fig. 4, Table 1). Hence both the TOC and S2 yields from the samples studied indicate very good potential source rocks for oil and gas. The samples have moderate to high TOC contents, especially

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Figure 3. Lithostratigraphic logs of the three wells studied, Block 16, Qamar Basin. For key to lithological symbols, see Figure 2.

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6.2. Kerogen types

Figure 4. Plot of S2 versus TOC (total organic carbon) showing hydrocarbon potential and source rock efficiency. Most of the samples studied are within the fair to excellent zones. Abbreviations: P, poor, F, fair, G, good, VG, very good, E, excellent.

within the depth range of 3256e3327 and 3393 m, with an average value 6.38 wt% in the 16/G-1 well, and at depths of 2958e 3048, 3073e3175, 3084, 3102e3165, 3174e3184, 3193e3202, 3238e3256 and 3292e3300 m, with an average value 23.56 wt% in the 16/U-1 well (Figs. 14 and 15, Table 1). Moderate to high values of TOC are also recorded from the following depths in the Al-Fatk-1 well: 3362e3372, 3402e3426, 3501e3507, 3525, 3534, 3543, 3552, 3558, 3602, 3645e3690, 3780, 3830 and 4158 m, with an average value of approximately 13 wt% (Fig. 16, Table 1). The highest TOC values (usually more than 10 wt% TOC) are recorded from the coal beds (Table 1, Figs. 4e6, 14e16). High to very high values of TOC wt% content at some levels are related to multiple occurrences of coal layers in the Mukalla Formation. The coals are extremely rich sources of gas and oil, whereas the shales and claystone interbeds range from fair to very good source rocks in the three wells (Figs. 14e16). The plot of TOC versus PP indicates moderate to good potential for petroleum for the Mukalla Formation; most of the samples are located within the fair to excellent zones (Fig. 5). In combination with other Rock-Eval parameters, namely the relationships between TOC and HI, and PI and Tmax, the samples studied indicate good source rocks for petroleum within the hydrocarbon generation zone (Figs. 4e9). Figures 10e12 show average concentration maps of TOC, PP and PI for the formation; these indicate an increase in a south-westerly direction and a high anomaly area between and around the locations of the 16/U-1 and 16/G-1 wells in Block 16 of the Qamar Basin.

Figure 5. Plot of PP (petroleum potential) versus TOC (total organic carbon) indicating hydrocarbon potential. Most of the samples studied are within the fair to excellent fields. For abbreviations, see caption to Figure 4.

Our oil-show analysis measured the free gas (S0) and free oil (S1) in a rock sample, the hydrocarbons from cracking residual kerogen in the rock (S2), and the CO2 resulting from oxidation of the residual carbon (S3) (Espitalié et al., 1984). TOC was calculated as the sum of the pyrolysis and residual organic carbon. The S3 for calculating the oxygen index (OI) was replaced by S4 for determining TOC. This eliminates the use of OI as a kerogen-type indicator (comparable to O/C in the Van Krevelen diagram). The kerogen-type designations are based entirely on the HI (Hunt, 1996). The interpretation of kerogen type is, however, somewhat improved with the HI versus TOC plot (Fig. 6). Figures 8 and 9 show HI versus Tmax plots for the samples studied, most of which are mature and contain type II/III and III kerogen with Tmax values ranging between 435 and 460  C, and an average value of 440  C in the 16/G-1 well, 446  C in the 16/U-1 well and 450  C in the Al-Fatk1 well. These figures confirm that the succession studied is mature with respect to generation of gas and oil from kerogen types II/III and III. Kerogen type can also be determined by optical (palynological) methods. Observations under a light microscope indicated a common occurrence of types II/III and III, a mixture of SOM of both marine and terrestrial origin contributing to type II/III (see Section 7 below). 7. Maturation and palaeothermal indicators As noted above (Section 5), several categories of data and parameters are used to evaluate the degree of organic maturity; these include TAI, Ro, and Tmax (Killops and Killops, 1993, 1995; Hunt, 1996; Peters et al., 2005). Thermal maturity is widely considered (e.g., Peters, 1986) to be equivalent to a vitrinite reflectance of 0.6% (Tmax 435  C). The top and bottom of the oil and gas generation “window” vary according to the type of organic matter, ranging from 0.5 e 1.0% Ro to 1.4e3.5% Ro, respectively (Espitalié et al., 1984; Tissot and Welte, 1984). Thermogenic oil is thought to be generated at Ro values above 0.6% Ro for kerogen types I and II (e.g., Bordenave, 1993). The lowest value of vitrinite reflectance associated with known generation of conventional oil is about 0.5% Ro, and 0.6% Ro is generally recognized as marking the beginning of commercial oil accumulation. The peak of oil generation is linked to values of around 0.8e1% Ro. At progressively higher Ro levels, gas/oil ratios increase rapidly. The values obtained for the samples examined are mostly less than 1% Ro except for one at 3885 m in the 16/G-1 well, one at

Figure 6. Plot of HI (hydrogen index) versus TOC (total organic carbon) indicating hydrocarbon potential and kerogen types. Most of the samples studied are within the fair to excellent fields and kerogen types II/III and III. For abbreviations, see caption to Figure 4.

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Table 3 Vitrinite reflectance data for the wells studied. 16/G-1 well

16/U-1 well

Al-Fatk-1 well

Depth (m) R0 (read. no.) Depth (m) R0 (read. no.) Depth (m) R0 (read. no.) 3256 3271 3393 3516 3579 3609 3699 3759 3789 3879 3885 Average

0.57(50) 0.61(50) 0.62(50) 0.69(50) 0.71(47) 0.75(13) 0.78(50) 0.82(23) 0.87(17) 0.95(18) 1.01(30) 0.76

2895 2967 3030 3102 3174 3238 3292 Average e e e e

0.66(31) 0.68(50) 0.74(50) 0.75(39) 0.80(50) 0.84(50) 1.00(48) 0.8 e e e e

3269 3368 3488 3500 3557 3671 3680 3752 3827 3962 4157 4298 Average

0.45(13) 0.53(36) 0.57(44) 0.62(33) 0.70(28) 0.72(32) 0.73(39) 0.76(12) 0.77(35) 0.94(32) 1.07(24) 1.20(31) 0.75

3292 m in the 16/U-1 well, and two at 4157 m and 4298 m in the AlFatk-1 well (Table 3). The minimum value recorded is 0.57 Ro at 3256 m in the 16/G-1 well, so most of the samples are within the range of the oil-generation zone, with average values of 0.76 Ro in the 16/G-1, 0.8 Ro in the 16/U-1, and 0.75 Ro in the Al-Fatk-1 wells (Fig. 17). Thermal maturity of the organic matter was also estimated from the Tmax versus PI plot from the Rock-Eval pyrolysis (Fig. 7). According to Tissot and Welte (1984), the zone of oil generation ranges between Tmax temperatures of 435 and 460  C and between PI values of 0.1 and 0.4. The average PI values for the Mukalla samples are over 0.10 (Table 1, Fig. 7), indicating that the formation is thermally mature. In addition to determining the degree of maturation, the relationship between Tmax and PI (Fig. 7) can be used to indicate the nature of the hydrocarbon products (i.e., whether indigenous or migrated). Based on this relationship, the samples examined are thermally mature and the hydrocarbons are indigenous. Most Tmax values range between 430 and 460  C (Table 1). Tmax is considered here to be most reliable when derived from samples where S2 equals 0.4 mg HC/g rock, whereas PI is considered most reliable when derived from samples having a TOC of 0.5 wt% (Table 1). The Tmax results from the three wells studied and available Tmax data from neighbouring wells (Wadi Jiza-1 and 16/E-1) were used to generate a map of Tmax distribution in the study area (Fig. 13). This figure indicates anomalies of Tmax in the northeastern part of Block 16 and the Qamar Basin. Generally, Ro values increase with depth as temperatures gradually increase (thermal gradient) and commonly also with the age

of rocks. The mean random Ro values for all samples reported herein ranges from 0.57 to 1.01% in the 16/G-1 well, from 0.66 to 1.0% in the 16/U-1 well, and from 0.45 to 1.2% in the Al-Fatk-1 well (Table 3). These values indicate thermal maturity of oil- and gasprone organic matter and hence potential for oil and gas generation (Table 3, Fig. 17). Tmax values range from 433 to 472  C with an average of 450  C for the Al-Fatk-1 well, from 439 to 454  C with an average of 446  C for the 16/U-1 well and from 425 to 450  C with an average of 439  C for the 16/G-1 well (Table 1, Fig. 17). These results correlate well with the measured Ro, reliably indicating maturity of oil- and gas-prone organic matter, and confirming that the samples analysed are within the oil window (approximately 0.6e1.2% Ro; Tissot and Welte, 1984; Hunt, 1996). HI values are low in the upper part of the Mukalla Formation in the 16/U-1 and AlFatk-1 wells compared to those of the middle and lower parts of these wells (Table 1, Figs. 15 and 16), but higher in the upper part of the Mukalla Formation than in the lower part of the 16/G-1 well (Table 1, Fig. 14). The distribution of Ro values suggests that most of the Mukalla mudstone, non-calcareous and calcareous shale, and coal samples are sufficiently mature to generate oil and gas (Table 3, Fig. 17). The thermal maturity of the organic matter in the samples was also evaluated on the basis of the Tmax of the pyrolysis S2 peak. The maturation range of Tmax has been found to vary for different types of organic matter (Tissot and Welte, 1984; Peters, 1986; Bordenave, 1993). Tmax is narrow for kerogen type I but wider for type II and much wider for type III owing to the increasing structural complexity of the organic matter (Tissot et al., 1987). The maturation window for oil/condensate generation from organic matter types I and II ranges from 430 to 470  C and for dry gas generation is more than 470  C (Peters, 1986; Tissot et al., 1987). The oil window for type III terrigenous organic matter ranges from 465 to 470  C, whereas the condensate/wet gas window corresponds to a Tmax of up to 540  C (Bordenave, 1993). Figure 9 shows the HI versus Tmax plot for the samples studied, which are in the mature petroleum generating range (430e475  C). Again, most of the kerogen is of type II/III and type III, which fits with the predominance of oil- and gas-prone source rocks. Most of the spores and pollen grains recovered from the sections studied display a gradual change in colour with increasing depth from dark yellow to orange-brown (Table 2, Fig. 21). Estimates of TAI were based mainly on the most abundant genera, namely the Cyathidites/Deltoidospora group and similar smooth-walled spores (as noted in Section 5), but when not represented, the colour of such pollen grains as Exesipollenites and Inaperturopollenites was recorded. Samples from the uppermost part of the Mukalla Formation yielded palynomorphs that are predominantly dark orange, i.e., indicating a TAI of 5, at depths of 3201e3360 m in the 16/G-1 well and 2868e2931 m in the 16/U-1 well (Table 2). The palynomorphs from the middle and lower parts of the formation are mainly light to dark brown, i.e., indicating a TAI of 6e8, for depth intervals of 3366e3885 m in the 16/G-1 well, 2940e3300 m in the 16/U-1 well and 3255e4300 m in the Al-Fatk-1 well, reflecting increasing depth of burial and geothermal gradient and peak catagenesis stages of maturation (Table 2, Fig. 17). All three palaeothermal indicators, Ro, Tmax and TAI, recorded from the wells examined are summarized in Figure 17. They are compatible and indicate increasing maturation with depth, reaching the catagenesis maturation stage for the deepest section. 8. Hydrocarbon generation

Figure 7. Plot of Tmax (maximum temperature) versus PI (production index) indicating that nearly all of the samples studied are within the hydrocarbon generating zone.

The TOC recorded from sedimentary rocks reflects the amount of kerogen they contain. As noted above, deposits having a thermal maturity equivalent to a vitrinite reflectance of 0.6% (Tmax 435  C)

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and an HI above 300 mg HC/g TOC will produce oil; those with an HI between 300 and 150 will produce oil and gas; those with an HI between 150 and 50 will yield only gas; and those with an HI that is less than 50 are inert. Pyrolysis data show that the hydrocarbon richness of a sedimentary rock is dependent upon the hydrogen content (reflected in the hydrogen index), irrespective of whether it is shale or a coal (Peters, 1986). Other indications of organic content are thermal cracking of the organic matter by pyrolysis, with S1 indicating the existing petroleum content and S2 the remaining petroleum-generating potential of kerogen in the rock (Peters, 1986; Hunt, 1996). High S1 values may indicate effective source rocks or rocks containing migrated oil. S2 is a more realistic measure of source rock potential than TOC because the latter includes “dead carbon”, which is incapable of generating petroleum. As noted above (Section 6.1), a plot of PP against TOC content on a Tissot and Welte (1984) diagram (Fig. 5) indicates that most of the samples examined fall within fair to excellent zones, particularly those of the 16/U-1 well: PP values range from 0.4 to 338.3 mg HC/g of rock in the 16/G-1 well, 0.69 to 272.7 mg HC/g of rock in the 16/U1 well and 0.18 to 282.7 mg HC/g of rock in the Al-Fatk-1 well (Table 1, Fig. 5). According to Langford and Blanc-Valleron (1990), plots of S2 versus TOC eliminate problems caused by matrix effects and also give a better evaluation of present-day hydrocarbon generating potential than normal HI/OI plots (Fig. 4). Similarly, plots of PP with TOC are also used to estimate potential S2 and effective S1 hydrocarbon-producing capacity with minimizing effects (Fig. 4). The samples from the Mukalla Formation are characterized by containing mature organic matter with a Tmax range of 425e450  C and an HI up to 373 mg HC/g TOC in the 16/G-1 well, 439e454  C and an HI up to 374 mg HC/g TOC in the 16/U-1 well and 433e 472  C and an HI up to 378 mg HC/g TOC in the Al-Fatk-1 well (Table 1, Figs. 8 and 9), which suggests that the Mukalla Formation not only contains kerogen types II/III and III capable of generating oil and gas but also is located within the oil and condensate-wet gas windows of hydrocarbon generation. A few samples from the AlFatk-1 well reach the early dry-gas zone (Figs. 8 and 9). PI typically climbs from 0.1 to 0.4 from the beginning to the end of oil generation (Hunt, 1996). Most of the PI values of the samples studied are within the oil-generation window, having average maximum and minimum values of 0.07, 0.2 and 0.02 respectively (Table 1, Fig. 12).

79

Figure 9. Plot of HI (hydrogen index) versus Tmax (maximum temperature) of the Mukalla Formation indicating the thermally mature zone and kerogen types II/III and III, vitrinite reflectance (Ro) data delineating the limits between the zones of maturation and kerogen types.

Hydrocarbon generation depends upon the occurrence of a sufficient quantity of suitable organic matter and an appropriate level of thermal maturation. Commonly the high content of types II/III and III kerogen in the samples studied indicate that most of the Mukalla Formation is at the peak of oil and gas generation. This is supported by the Tmax versus PI (Fig. 7) and HI versus Tmax plots (Figs. 8 and 9). These indicate the presence of large amounts of kerogen type III and lesser amounts of kerogen type II/III, which are mostly thermally mature and have potential to generate oil and gas. Hydrocarbon expulsion from the Mukalla Formation source rocks may have commenced during the early Paleogene and continued into the late Neogene in association with the vast floods of lava that erupted during rifting of the Red Sea and Gulf of Aden. Using software program Surfer 7, the TOC, PP and PI results of the three wells examined as well as similar data from neighbouring wells Wadi Jiza-1 and 16/E-1, average concentration maps for the Mukalla Formation were constructed (Figs. 10e12). Figure 10 indicates TOC anomalies in the 16/G-1 well in the southern part of Block 16 and the Qamar Basin generally. Figure 11 shows PP anomalies in the 16/G-1, 16/U-1 and Wadi Jiza-1 wells towards the southern to south-western parts of the Block 16. Figure 12 indicates PI highs around the 16/G-1 well and southern part of this block. 9. Organic geochemical logs

Figure 8. Modified Van Krevelen plot of HI (hydrogen index) versus Tmax (maximum temperature) of the Mukalla Formation indicating the thermally mature zone and kerogen types II/III and III.

The organic geochemical data indicate that sufficient organic matter is preserved within the Mukalla Formation for it to be regarded as having potential for hydrocarbon generation (Table 1). Most of the samples analysed have TOC values greater than the critical lower limit of 0.5 wt % (e.g., Tissot and Welte, 1984; Hunt, 1996). The organic geochemical log is considered to be the most powerful tool for determining and interpreting the source rock potential and hydrocarbon generation of the formation. It records TOC, S1, S2, PI, HI, Tmax and PP versus depth for 3256e3885 m in the 16/G-1 well, 2868e3300 m in the 16/U-1 well, and 3251e4158 m in the Al-Fatk-1 well (Figs. 14e16). These figures are based on TOC/

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Figure 10. TOC (total organic carbon) average distribution map of Block 16, Qamar Basin, showing concentration in the south-western part.

Figure 11. PP (petroleum potential) average distribution map of Block 16, Qamar Basin, showing concentration in the southern part.

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Figure 12. PI (production index) average distribution map of Block 16, Qamar Basin, showing concentration in the southern to south-eastern part.

Figure 13. Tmax (maximum temperature) average distribution map of Block 16, Qamar Basin, showing concentration in the northern part.

81

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Figure 14. Organic geochemical log of the Mukalla Formation in the 16/G-1 well according to Rock-Eval pyrolysis/TOC (total organic carbon) results. These representative curves are based on lowemoderate rather than on high values, the latter (>0.5 wt% TOC) being sufficient to generate hydrocarbons. For key to lithological symbols, see Figure 2.

Figure 15. Organic geochemical log of the Mukalla Formation in the 16/U-1 well according to Rock-Eval pyrolysis/TOC (total organic carbon) results. For observations on the representative curves, see caption to Figure 14. For key to lithological symbols, see Figure 2.

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Figure 16. Organic geochemical log of the Mukalla Formation in the Al-Fatk-1 well according to Rock-Eval pyrolysis/TOC (total organic carbon) results. For observations on the representative curves, see caption to Figure 14. For key to lithological symbols, see Figure 2.

Figure 17. Palaeothermal log of Tmax (maximum temperature), Ro (vitrinite reflectance) and TAI (thermal alteration index) versus depth of the Mukalla Formation in the three wells studied.

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Figure 18. GC (gas chromatography) and differing hydrocarbon richness of the Mukalla Formation in the Qamar Basin.

Rock-Eval pyrolysis data and indicate a large quantity of high quality source rocks in the succession. 10. Gas chromatography Gas chromatography (GC) is used to separate components of a sample by their partition differences. Various parameters are used to provide information for our study. Kerogen type and its ability to generate hydrocarbons can be determined by GC. Oil-prone kerogens show a full spectrum of C1eC28 n-alkanes with a high concentration of C11þ compounds, whereas gas-prone kerogens are characterized by the predominance of light hydrocarbons from C1 to C5 and higher contributions of aromatic compounds (Dembicki et al., 1983). Mixed kerogens are intermediate in character. The GC results for most of the samples from the Mukalla Formation from the three wells studied are

Figure 19. Oil families and characterization zones for the Mukalla Formation. 1, gas and condensate; 2, paraffinicenaphthenicearomatic oil (high wax); 3, paraffinice naphthenicearomatic oil (low wax); 4, paraffinic oil (low wax); 5, paraffinic oil (high wax).

recognized to be both gas- and oil-prone from mixed kerogen types (Tables 4e6, Figs. 18e20). Figure 18 and Table 4 show that the lighter hydrocarbons (C1eC5) are more concentrated within the upper part of the formation in the 16/G-1 well, within the range depth of 3256e3393 m; these decrease in the deeper part of the formation, commensurate with an increase in intermediate to heavier hydrocarbons (C6eC14 and C15þ). Light hydrocarbons dominate the recovery from the upper part of the formation in the 16/U-1 well that was analysed (Fig. 18, Table 4). The part of the formation in Al-Fatk-1 well within the depth range of 3383e 3533 m that was measured also yielded a high concentration of lighter hydrocarbons (Fig. 18, Table 4). Hydrocarbon extraction and amounts of asphaltene, saturated, aromatic and the ratio of saturated to aromatic components were obtained from three samples from the Al-Fatk-1 well (Table 5). Comparison of the results of these analyses shows that asphaltenes are more abundant than other components (Table 5).

Figure 20. Pristane/nC17 versus phytane/nC18 cross-plot shows kerogen type, maturation, biodegradation and depositional environments of the Mukalla Formation.

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Table 4 GC (gas chromatography) and hydrocarbon richness (C1eC15þ) results for the Mukalla Formation. Well

Depth (m)

C1%

C2eC5%

C6eC14%

C15þ%

nC17%

Toluene nC8

Phenol%

C1eC5%

16/G-1

3256 3259 3266 3269 3270 3271 3393 3399-3429 3489-3519 3256 3266 3300 3383 3488 3533

7.86 10.36 11.19 9.09 8.33 11.00 12.69 9.42 8.50 17.71 12.27 26.85 23.69 25.57 28.35

24.41 34.56 42.11 37.24 38.46 27.16 33.84 10.12 14.20 22.35 24.63 34.65 43.36 28.57 30.79

32.95 27.00 31.76 29.99 32.02 34.68 32.31 25.96 28.70 44.61 43.03 22.21 29.63 34.04 29.91

34.78 28.08 14.94 23.68 21.19 27.16 21.15 54.50 48.60 14.24 18.99 15.00 3.32 11.82 10.96

0.41 0.20 0.34 0.31 0.25 0.71 0.44 0.53 0.61 1.09 1.09 1.28 1.90 0.15 0.72

2.53 0.76 2.24 1.88 1.87 2.19 2.25 2.01 3.11 2.49 1.33 2.08 1.90 1.33 1.35

0 0 0 0 0 0 0 0 0 0.07 0.06 0.08 0.14 0.24 0.09

32.27 44.92 53.30 46.33 46.79 38.16 46.53 19.54 22.70 40.06 36.90 61.50 67.05 54.14 59.14

16/U-1

Al-Fatk-1

Normal alkanes have been used successfully as biomarkers because of their abundance and ease of detection by GC (Peters et al., 2005). The concentration and distribution of n-alkanes in source rock extracts are affected by variations in the source and type of organic matter, maturity level and biodegradation or other alteration processes. The carbon preference index (CPI) is a parameter that quantifies the ratio of odd-to-even numbered nalkanes in a sample (Table 6). Lipid and cuticular waxes, derived from higher plants, will contribute n-alkanes in the range of C10e C40, with the hydrocarbon envelope shifted towards higher molecular weight n-alkanes and having a much higher concentration of odd-numbered (nC27, nC29 and nC31) than even numbered (nC28 and nC30) alkanes (Tissot and Welte, 1984; Smith et al., 2004). Conversely, marine phytoplankton exhibit a distinct mode in the range nC10enC20, with a predominance of nC15, nC17 and nC19 (Tissot and Welte, 1984; Connan et al., 1986). The concentration and distribution of n-alkanes in source rock extract samples from the Mukalla Formation indicate (cf. Smith et al., 2004) abundant to common concentrations of lipid and cuticular waxes derived from higher plants with rare to common concentrations of marine phytoplankton at different levels in the formation (Tables 4e6, Figs. 18e20). An isoprenoid pristane/n-C17 versus isoprenoid phytane/n-C18 cross-plot is used to determine kerogen type, maturation, biodegradation and depositional environment (Hunt, 1996; Peters et al., 2005). Figure 20 shows that four samples from the Al-Fatk-1 well and one from the 16/G-1 well are located within the maturation and oxidizing zones in which terrestrial organic matter (kerogen type III) was preserved, and two samples from these wells are located within the maturation zone but in the reducing part, which led to the accumulation of mixed organic matter (kerogen type II/ III). On the other hand, two samples from the Al-Fatk-1 well are located within the biodegradation and reducing zones, which led to the preservation of marine organic matter (kerogen type I). The most widely used biomarker parameter for assessing redox conditions during sediment accumulation is the pristane/phytane (Pr/Ph) ratio. The fact that the ratio of these two acyclic isoprenoid

Table 5 Extraction amounts for selected samples from the Al-Fatk-1 well. Depth TOC (m) 3365 3401 3533

Total ext.

Sat.

Aro.

Total HC Asph. Sat/ HC% of Eluted in ext.% Aro. total ext. NSOs

1.50 160.67 38.58 17.78 56.36 1.56 125.29 22.44 28.01 45.45 12.80 96.50 20.22 13.92 34.14

53.91 2.17 35.08 55.51 0.98 36.27 55.89 1.45 35.38

49.91 24.07 6.41

alkanes is influenced by the degree of oxygenation was first noted by Brooks et al. (1969), but developed and popularized by Didyk et al. (1978). These latter authors proposed that pristane/phytane ratios of >1 indicate oxic conditions of sedimentation (at the sediment/water interface), whereas ratios of <1 reflect anoxic conditions. These values have often been applied by authors subsequently without due consideration of the complexities that impact on this ratio. Peters et al. (2005) recommended that the ratio should not be used for immature samples and noted that even within the oil window values between 0.8 and 3 are equivocal. High Pr/Ph values (>3) are common in samples with abundant terrestrial organic matter deposited under oxic conditions, whereas very low values (<0.8) are common in hypersaline environments where anoxic conditions typically prevail. The n-alkane gas chromatograms of seven selected source rock samples between depths of 3365 and 3698 m in the Al-Fatk-1 well show a predominance of

Table 6 GC (gas chromatography) n-alkane and isoprenoid data from the Al-Fatk-1 and 16/ G-1 wells. Well Depth (m) Al-Fatk-1

nC15 nC16 nC17 nC18 nC19 nC20 nC21 nC22 nC23 nC24 nC25 nC26 nC27 nC28 nC29 nC30 nC31 nC32 nC33 nC34 nC35 CPI 1 Ind. CPI 2 Ind. CPI 3 Ind. Prist/Phyt Prist/nC17 Phyt/nC18

16/G-1

3365

3368 3401

12.52 9.23 6.01 6.55 5.19 5.80 4.97 4.72 4.69 4.58 4.62 4.90 5.30 5.04 5.65 3.76 3.58 1.43 0.86 0.50 0.11 1.00 1.16 1.07 2.99 2.87 5.34

2.74 2.93 3.39 3.27 3.39 3.61 4.03 4.99 5.03 5.14 4.82 5.24 5.52 5.14 6.04 4.05 3.79 2.11 2.03 1.17 0.75 1.14 1.13 1.06 6.27 2.98 0.49

3533

3557 3671 3698 3390

11.23 11.07 1.68 9.07 8.94 2.99 5.36 6.39 3.63 6.89 6.60 4.15 5.73 6.36 4.73 5.37 5.40 4.88 4.95 5.27 5.91 5.36 5.46 6.83 5.29 5.27 7.30 5.02 5.27 7.30 5.20 5.14 6.81 5.13 5.40 6.24 6.01 5.30 5.80 5.55 5.08 5.08 6.36 5.03 5.35 4.35 2.85 3.36 2.17 2.55 2.68 0.28 1.14 1.38 0.50 0.90 1.42 0.12 0.48 0.76 0.03 0.11 0.53 1.02 0.98 1.13 1.14 1.11 1.11 1.13 1.01 1.02 1.42 0.44 4.96 1.92 0.52 1.76 1.96 0.35 0.31

3.95 4.35 4.65 4.67 5.03 4.83 4.89 5.19 5.34 5.60 5.43 5.27 5.08 4.42 4.30 2.53 1.84 1.02 1.16 0.62 0.30 1.12 1.10 1.05 5.27 1.10 0.20

4.10 4.14 4.46 4.49 4.91 4.92 5.13 5.42 5.65 5.99 5.92 5.81 5.59 4.60 4.49 2.45 1.52 0.61 0.81 0.43 0.19 1.13 1.12 1.07 6.95 0.98 0.14

10.99 11.57 10.41 9.69 10.70 7.08 5.78 5.06 4.34 3.61 2.86 2.91 2.84 2.29 2.74 1.75 2.36 1.26 0.88 0.46 0.41 0.99 1.17 1.09 1.18 0.52 0.47

3426 7.10 6.82 5.56 6.14 5.81 4.95 4.65 4.30 4.20 4.60 4.72 5.32 5.91 6.02 7.10 5.25 5.42 2.99 1.91 0.75 0.49 0.99 1.14 1.04 3.43 1.66 0.44

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moderate to longer chain length, waxy normal alkanes with high ratios of pristane/phytane ranging between 0.44 and 6.95 (Table 6). These ratios indicate a predominance of shale source rock containing common to abundant terrestrial organic matter reflecting deposition under oxic to sub-oxic conditions. The Pr/Ph ratios of two samples from depths 3390 m and 3426 m in the 16/G-1 well are 1.18 and 3.43, which also indicate shale source rock containing abundant terrestrial organic matter that was deposited under oxic to sub-oxic conditions (Table 6). On the other hand, biomarker compositions of source rocks (and their resulting oils) are influenced by lithology (particularly clastic versus carbonate types).

Such influences may be related to interactions between biomarkers and the minerals themselves (especially clays). Hence, the Pr/Ph ratio is >1 if the source rocks are mainly composed of shale that reflects deposition within deltaic and shallow marine environments, and <1 if the source rocks mainly consist of carbonate (Peters et al., 2005). According to our GC results, the selected samples from the Mukalla Formation in the Qamar Basin that we studied represent mixed kerogen type II/III and terrestrial kerogen type III reflecting deposition within sub-oxic to sub-dysoxic depositional environments. These organic materials were thermally matured

Figure 21. Transmitted light photographs of selected palynomorphs and sedimentary organic matter (SOM) from the Mukalla Formation. The measurements provided are maximum dimensions. 1, representatives of the Deltoidospora/Cyathidites group and similar smooth-walled forms such as the specimen of Concavisporites sp. shown here (diameter 35 mm) were used to measure TAI (thermal alteration index). 2, Verrucosisporites sp. (45 mm). 3, Foveotriletes margaritae (47 mm). 4, Ariadnaesporites sp. cf. A. spinocaperatus (spore body 52 mm, surrounded by long processes). 5, Araucariacites sp. (60 mm). 6, Cycadopites sp. (22 mm). 7, 19, Longapertites sp. (61 and 50 mm). 8, 16, Multicellaesporites spp. (length 45 mm). 9, Monocolpopollenites sp. (55 mm). 10, Echimonocolpites sp. (32 mm). 11, Ctenolophonidites costatus (45 mm). 12, Arecipites sp. (50 mm). 13, Cristaecolpites spp. (54 mm). 14, Retistephanocolpites sp. (55 mm). 15, cf. Circulodinium sp. (65 mm). 17, Spinizonocolpites spp. (45 mm). 18, Tricolpites sp. (33 mm). 20, Pediastrum sp. with much embedded pyrite (maximum diameter 50 mm). 21, Membranilarnacia sp. (75 mm). 22, Andalusiella mauthei sp. (70 mm). 23, cf. Cribroperidinium sp. 24, Odontochitina operculata (diameter of body 65  55 mm, horn lengths 105 and 125 mm). 25, Palaeohystrichophora infusorioides (width 45 mm). 26, Cleistosphaeridium sp. (31 mm). 27, Spiniferites sp. (45 mm). 28, Florentinia sp. (55 mm). 29, Oligosphaeridium sp. (58 mm). 30, Coronifera sp. (50 mm). 31, Cerodinium granulostriatum (65 mm). 32, Foraminiferal test lining (length 135 mm). 33, Palynofacies 1 (PF1  200). 34, Palynofacies 2 (PF2  250). 35, Palynofacies 3 (PF3  150).

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(catagenesis stage) during the Palaeogene and Neogene, the maturation event in turn resulting from the opening of the Gulf of Aden (Table 6, Fig. 20). As a consequence, the basin is expected to yield heavy to medium crude oil and natural gas. 11. Palynofacies, depositional environments and palaeoclimate 11.1. Sedimentary organic matter and palynomorphs Following processing of all samples using standard palynological techniques (see Section 5) 200 or more particles of SOM greater than 10 mm in maximum diameter were counted from each preparation and referred to nine major kerogen groups (Table 2, Figs. 22e24). The amorphous organic matter (AOM) consists of heterogeneous, structureless aggregates of material with diffuse outlines and common inclusions that usually range between 10 and 300 mm in maximum diameter. It is of both aquatic and terrestrial derivation and includes algal, fungal and bacterial material as well as microplankton, miospores and rotted, gelified wood (e.g., Batten, 1996a). All such components, whether amorphous or not, differ in their significance with respect to the generation of hydrocarbons and therefore aid the evaluation of potential source rocks (Batten, 1980, 1996b; Brooks, 1981; Tissot and Welte, 1984; Thompson and Dembicki, 1986; Tyson, 1995). The amount of hydrocarbons generated is controlled by not only the quantity and type of SOM but also its maturity. Data obtained by transmitted light microscopy of the organic matter in the palynological slides from the Mukalla Formation are recorded in Table 2. The palynomorph assemblages are characterized by containing low numbers of marine dinoflagellate cysts (dinocysts), acritarchs, and linings of foraminiferal tests (FLT on Figs. 22e24), and common to abundant land-derived

87

palynomorphs, reflecting deposition in shallow marine conditions. Dinoflagellate cysts are less common in the upper part of the formation, probably reflecting a gradual marine regression. Comparison of the palynomorph content of the Mukalla Formation in the 16/U-1 onshore well with that of the 16/G-1 offshore well indicates that the marine transgressions are reflected by deposition of sediments rich in organic matter. Overall, many transgressive and regressive events within the synrift stage of development of the Qamar Basin are indicated by variations in the abundance of land-derived miospores, freshwater algae, phytoclasts and other organic matter (Table 2, Figs. 21e26). The most abundant marine dinoflagellate cysts are Andalusiella mauthei, Cerodinium granulostriatum, Palaeohystrichophora infusorioides and Spiniferites spp. (Fig. 21). Most of the spores (e.g., Concavissimisporites, Cyathidites/Deltoidospora, Verrucosisporites) are attributable to ferns, including water ferns (Ariadnaesporites), but hepatic spores such as Zlivisporis blanensis are present and sometimes common constituents. Gymnosperms are mostly represented by inaperturate pollen referable to Araucariacites or Inaperturopollenites of probable coniferalean derivation. Angiosperm pollen grains are by far the most common and morphologically diverse of the terrestrial palynomorphs. Longapertites, Monocolpites and Spinizonocolpites, typical of the late Cretaceous ‘Palmae Floral Province’ (Schrank, 1994) are common to dominant and, together with the associated spores, indicate warm, humid conditions during deposition of the Mukalla and younger Cretaceous formations in the Qamar Basin. Other miospores that occur as minor to common elements include Arecipites, Ctenolophonidites costatus, Cycadopites/Monosulcites, Echitriporites, Retimonocolpites and Tricolpites (Fig. 21). Fungal palynomorphs typically occur in assemblages that reflect high terrestrial input but are always rare. They are orange to light brown in colour and consist of both filamentous hyphal components of mycelia and spores. Freshwater algae (Pediastrum; Fig. 21)

Figure 22. Log of the content of sedimentary organic matter (SOM), i.e., palynological components and palynofacies, versus depth in the offshore 16/G-1 well. Abbreviations: FLT, linings of foraminiferal tests; AOM, amorphous organic matter; TAI, thermal alteration index; PF, palynofacies. The heading ‘Palynomorphs’ refers to the sum total of pollen, spores, dinocysts, acritarchs, foraminiferal linings and fungal remains.

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Figure 23. Log of the content of sedimentary organic matter (SOM), i.e., palynological components and palynofacies, versus depth in the onshore 16/U-1 well. For abbreviations and explanation of the heading ‘Palynomorphs’, see caption to Figure 22.

Figure 24. Log of the content of sedimentary organic matter (SOM), i.e., palynological components and palynofacies, versus depth in the offshore Al-Fatk-1 well. For abbreviations and explanation of the heading ‘Palynomorphs’, see caption to Figure 22.

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11.2. Palynofacies types

Figure 25. Ternary diagram of MSP (microplankton, spores, pollen; cf. Tyson, 1995) indicating offshoreeonshore depositional, transgressiveeregressive trends and environments reflected by the Mukalla Formation.

are rare to common, comprising a significant proportion of the total of palynomorphs recorded from some samples. The presence of such algae (also Chomotriletes spp.) indicates coastal swamps and lacustrine environments in western and north-western parts of the Qamar Basin. Where Pediastrum is common in association with indicators of marine deposition, it is likely to have been transported from this region into the coastal lagoons and shallow marine environments of eastern, south-eastern and north-eastern parts (Alaug 2011a, b; Figs. 1, 21e26). Woody particles in the preparations range from translucent yellow or orange through pale brown in colour to semi-opaque and opaque, and angular and equidimensional to blade-like in shape. Most are probably derived from both coastal and inland vegetation to the north and north-west of the sites of deposition of the three wells examined (Fig. 21).

Palynofacies analysis is in many ways equivalent to analyses of the bulk organic geochemistry of sediments, but being based on visual observations of organic particles it provides more variables upon which to base determinations of sedimentary environment (e.g., Batten, 1980, 1996a,b; Tyson, 1995; Mustafa and Tyson, 2002). Both palynomorphs and associated SOM are useful indicators of depositional and other palaeoenvironmental conditions, as demonstrated by previous studies on rock successions in other parts of the world (e.g., Al-Ameri and Batten, 1997; Al-Ameri et al., 1999, 2001; Mustafa and Tyson, 2002). The three main constituents of palynofacies (SOM) usually considered in publications aimed at source potential for hydrocarbons are palynomorphs, AOM and phytoclasts. The palynomorph group includes miospores (sporomorphs) and its subgroups (spores and pollen grains), phytoplankton (subgroups dinoflagellate cysts and acritarchs) and zoomorphs (foraminiferal test linings and others). Palynologists concerned with petroleum potential frequently analyse the composition of AOM, because it is a useful indicator of the energy of a depositional site and is important as a potential source of hydrocarbons. The phytoclast group (including wood, cuticles and various tissues and filaments) has commonly received less attention, partly owing to difficulties in relating components to precise biological producers and partly because they have limited biostratigraphical value. Most macrophyte debris constituting the phytoclast group is hydrodynamically comparable to coarse silt or fine sand (e.g., Tyson, 1995). Following Tyson (1995), ternary AOM-palynomorph-phytoclast (APP) and ternary microplankton-pollen-spore (MPS) plots have been applied in this study (Figs. 25e26). The quantitative analysis of the palynological assemblages is based on counts of at least of 200 palynomorphs per sample. The predominance of AOM in several preparations meant that up to a dozen palynological slides had to be searched in order to record this number of specimens. Our data suggest the components of the palynofacies reflect both coastal and inland vegetation of the northern and northeastern parts of the Qamar Basin under the influence of a warm,

Figure 26. Ternary diagram of PAP (phytoclasts, AOM, palynomorphs; cf. Tyson, 1995) characterizing the kerogen assemblages recovered from the Mukalla Formation and the depositional environments indicated.

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humid, subtropicaletropical climate during the deposition of the SantonianeCampanian sediments of the Mukalla Formation (Table 2, Figs. 21e26). A seaward Nypa mangrove zone existed, and this was succeeded landward by wet lowlands where bryophytes, pteridophytes and palms thrived. Salvinialean water ferns and algae inhabited bodies of fresh water. The more elevated parts of the hinterland are likely to have been colonized by representatives of the Proteaceae and Coniferae, among other groups. The ternary plot in Figure 25 shows that most of the samples from the 16/G-1 well indicate offshore to near-shore environments, but those from the other two wells fall mainly within the field that indicates a near-shore environment. The ternary plot depicted in Figure 26 shows that most of the samples from the 16/G-1 well are located within field V, with some in field IV and elsewhere, whereas most of the samples from the 16/U-1 well are located within field IV. By contrast, most of the samples from the Al-Fatk-1 well are located in fields IV, VII and IX. According to Tyson (1995) these fields indicate shelfebasin transition (IV), oxic shelf (V), distal dysoxiceanoxic shelf (VII) and distal suboxiceanoxic basin (IX) deposits, all of which may be oil and/or gas prone. 12. Conclusions We have examined samples from sections through the late Cretaceous Mukalla Formation encountered in one onshore and two offshore exploration wells in the Qamar Basin, Yemen, using combined organic geochemical and microscopical techniques in order to determine its potential for the generation of both oil and gas. These consisted of TOC/Rock-Eval pyrolysis, gas chromatography, measurements of vitrinite reflectance, and an examination of acid-resistant sedimentary organic matter (kerogen) in transmitted light. The combined results of our analyses indicate that the formation contains both oil- and gas-prone kerogen with a peak thermal maturation stage for organic matter types II/III and III and good conditions for hydrocarbon generation and expulsion. The palynofacies recorded indicate that sediment deposition occurred in environments ranging from fluvio-deltaic through marginal- to shallow-marine and open marine environments, reflecting multiple marine transgressive and regressive phases during the deposition of the formation. The composition of the palynomorph assemblages associated with these facies suggests that a humid, subtropical to tropical climate prevailed throughout this period. Acknowledgements A.S. Alaug thanks the Petroleum Exploration and Production Authority-Republic of Yemen (PEPA) for providing samples and raw data upon which the present work is based, especially the previous chairman of PEPA Dr. Ahmed Abdullah and Eng. Abdulrauf AlSosoah in the databank section. He is also very grateful to the staff of the geology departments and their technicians in Assiut University (Egypt) and Taiz University (Yemen) for help during this study, and especially to Prof. Dr. Magdy S. Mahmoud. References Al-Ameri, T.K., Batten, D.J., 1997. Palynomorph and palynofacies indications of age, depositional environments and source potential for hydrocarbons: Lower Cretaceous Zubair Formation, southern Iraq. Cretaceous Research 18, 789e797. Al-Ameri, T.K., Al-Musawi, F.A., Batten, D.J., 1999. Palynofacies indications of depositional environments and source potential for hydrocarbons, uppermost Jurassic-basal Cretaceous Sulaiy Formation, southern Iraq. Cretaceous Research 20, 359e363. Al-Ameri, T.K., Al-Najar, T.K., Batten, D.J., 2001. Palynostratigraphy and palynofacies indications of depositional environments and source potential for hydrocarbons: the mid-Cretaceous Nahr Umr and lower Mauddud formations, Iraq. Cretaceous Research 22, 735e742.

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