Geochemical characteristics, depositional ...

Accepted Manuscript Geochemical characteristics, depositional environment and hydrocarbon generation modeling of the upper cretaceous Pakawau group in Taranaki Basin, New Zealand Nurhazwana Jumat, Mohamed Ragab Shalaby, AKM Eahsanul Haque, Md Aminul Islam, Lim Lee Hoon PII:

S0920-4105(17)31051-3

DOI:

10.1016/j.petrol.2017.12.088

Reference:

PETROL 4578

To appear in:

Journal of Petroleum Science and Engineering

Received Date: 17 August 2017 Revised Date:

23 December 2017

Accepted Date: 29 December 2017

Please cite this article as: Jumat, N., Shalaby, M.R., Haque, A.E., Islam, M.A., Lee Hoon, L., Geochemical characteristics, depositional environment and hydrocarbon generation modeling of the upper cretaceous Pakawau group in Taranaki Basin, New Zealand, Journal of Petroleum Science and Engineering (2018), doi: 10.1016/j.petrol.2017.12.088. This is a PDF file of an unedited manuscript that has been accepted for publication. As a service to our customers we are providing this early version of the manuscript. The manuscript will undergo copyediting, typesetting, and review of the resulting proof before it is published in its final form. Please note that during the production process errors may be discovered which could affect the content, and all legal disclaimers that apply to the journal pertain.

ACCEPTED MANUSCRIPT

4 5

Nurhazwana Jumat*1, Mohamed Ragab Shalaby1, AKM Eahsanul Haque1, Md. Aminul Islam1 & Lim Lee Hoon2

2

1

Department of Geological Sciences, Faculty of Science, Universiti Brunei Darussalam, Jalan Tungku Link, Gadong BE 1410, Brunei Darussalam 2 Department of Chemical Sciences, Faculty of Science, Universiti Brunei Darussalam, Jalan Tungku Link, Gadong BE 1410, Brunei Darussalam *Corresponding author (email: [email protected])

SC

6 7 8 9 10

RI PT

3

Geochemical Characteristics, Depositional Environment and Hydrocarbon Generation Modelling of the Upper Cretaceous Pakawau Group in Taranaki Basin, New Zealand

1

11

Abstract:

13 14 15 16 17 18 19 20 21 22 23 24 25 26 27 28 29 30 31 32

The oil, gas and condensate province of the Upper Cretaceous to Cenozoic Taranaki Basin is very important as it has become the sole commercially-producing sedimentary basin in New Zealand. An understanding of burial/thermal geo-histories of Taranaki Basin is essential for modeling hydrocarbon generation. In the present study, data from subsurface samples from selected wells have been analyzed and interpreted for characterizing source rock of the Pakawau Group along with thermal geohistory of the basin. The Upper Cretaceous Pakawau Group, made up of Rakopi (87-75 Ma) and North Cape (75-65 Ma) formations, is the eldest and most prolific organic rich hydrocarbon source rock in the basin. Their lithologies vary between carbonaceous mudstone and coal from alluvial to coastal plain depositional environments with marginal marine influence. Most samples that are interpreted contain kerogen Types II and II-III, with few samples of Type-III kerogen. This is validated by the biomarkers results, where the assessed data shows that the organic source ranges from terrestrial to marine origin. The Pakawau Group source is immature to mature, as reflected by the distribution of vitrinite reflectance (%Ro), pyrolysis Tmax from pyrolysis data and biomarkers data. Vitrinite reflectance distribution shows that the Rakopi Formation is mostly within the mature oil window for hydrocarbon generation with values ranging generally between 0.5% to 0.95% Ro. Using two selected wells, the models have been interpreted to generate hydrocarbons from the Pakawau Group between Upper Paleocene and Middle Eocene. Interpretations of the burial models confirm that hydrocarbons of Pakawau Group has not yet attained peak generation and is still being expelled from the source rock to-date.

33 34

Keywords: Pakawau Group, Rakopi Formation, North Cape Formation, Taranaki Basin, source rock evaluation, burial history

35

AC C

EP

TE D

M AN U

12

ACCEPTED MANUSCRIPT

Introduction

37 38 39 40 41

Geochemical signatures of a particular basin tell about important source rock information, such as its type, age, depositional environments and maturity of the area. The potential for any source rock to generate hydrocarbon is strongly reliant on its organic richness, volume and maturity (Tissot & Welte, 1984; Peters & Cassa, 1994). Different basins have different oil and/or gas generation mechanisms; hence, hydrocarbon generation study of a basin of interest is important.

42 43 44 45 46 47 48 49 50 51 52 53 54 55 56 57 58

The Taranaki Basin, which is the area of interest in this study, is the only commerciallyproducing sedimentary basin in New Zealand. It is located predominantly offshore on the west coast of the North Island. With an aerial extent of 100 000 km2, Taranaki Basin is one of the largest of a series of interconnected Cretaceous-Cenozoic sedimentary basins extending along the western margin of New Zealand. Numerous studies have been published about source rock characterization of the basin (Johnson et al., 1989; Collier et al., 1991; Killops & Frewin, 1994; Murray et al., 1994; Killops et al., 1998; Sykes & Snowden 2002; Wilkins & George, 2002; Jumat et al., 2017). The focus of this research work is in the analysis and interpretation of the volume and type of organic matter and the associated oil generation potential of the Upper Cretaceous Pakawau Group in the Taranaki Basin. The Pakawau Group, which comprises of Rakopi Formation and North Cape Formation, is the eldest and most prolific organic rich hydrocarbon source rock in the basin. This study aims to accomplish a comprehensive source rock characterization of the aforementioned Pakawau Group using a suite of secondary analyses on the primary data include the total organic content (TOC) content, rock eval pyrolysis and geochemical biomarkers. In addition, a robust basin modelling of the Pakawau Group is proposed in the study to provide better understanding of its burial history and potential for hydrocarbon generation.

SC

M AN U

TE D

1. Geological Setup of Taranaki Basin 1.1. General Geology

EP

59 60

RI PT

36

With an area of 100 000 km2, the Taranaki Basin is located along the west coast of New Zealand’s North Island (Fig. 1). This basin is predominantly offshore, mainly a subsurface feature beneath the continental shelf (Kamp et al., 2004). Cretaceous and Cenozoic rocks outcrop in several places around the present-day periphery of the basin that can be related to the subsurface sedimentary succession in Taranaki Basin (King & Thrasher, 1996). The main exposures are of Miocene deepwater successions along the north Taranaki coast, and of Cretaceous to Early Miocene terrestrial to shallow marine rocks in the north-western South Island. The Taranaki Peninsula is the largest onshore region, active faults occur onshore and offshore.

70 71 72

The geological evolution of Taranaki Basin has been covered in several studies, most notably by Thrasher (1992), King and Thrasher (1996), Palmer and Geoff (1988), Palmer (1985), Uruski (2008) and Pilaar and Wakefield (1978). The formation of Taranaki Basin was initiated from the

AC C

61 62 63 64 65 66 67 68 69

ACCEPTED MANUSCRIPT

breakup of the supercontinent Gondwana, which resulted in the separation between Australia and Zealandia. This formed the Tasman Sea and numerous extensional basins on the New Zealand subcontinent, including an intra-plate rift that formed the Taranaki Rift, which later developed into the Taranaki Basin during the Late Cretaceous (Baur et al., 2014; Kroeger et al., 2013; Thrasher, 1992). The basin evolved in three distinct phases. An initial rifting phase in the midCretaceous–Paleocene, associated with the break-up of eastern Gondwana, was accompanied by coal measure deposition in restricted, fault controlled basins. This was followed by the development of an Eocene–Early Oligocene passive margin, post-rift thermal contraction and regional subsidence. During this period, coal measures, including those of the Mangahewa Formation, were deposited on transgressive coastal plains and in marginal marine settings. Finally, in Oligocene–Recent times, the basin evolved to be an active marginal basin in response to development of the Australia-Pacific convergent plate boundary through New Zealand (King & Thrasher, 1996). These tectonic events have a major influence on the thermal and burial history of Taranaki Basin. Stratigraphically, the entire basin has an age range from Late Cretaceous to Recent (Fig. 2). Stratigraphic subdivision of the basin is based on seismic reflection mapping and lithostratigraphic, chronostratigraphic and allostratigraphic criteria derived from nearby wells and outcrop data. The Cretaceous–Cenozoic Taranaki Basin contains predominantly marine strata, but with significant terrestrial sedimentation occurring through the mid-Cretaceous to Eocene.

92 93 94 95 96

The Taranaki Basin is divided into two main geological regions: the relatively quiescent Western Stable Platform and The Eastern Belt, which is home to numerous tectonic processes and evolution. The wells in this study are located scattered across the two areas (Fig. 1). In the Eastern Belt, the Taranaki Basin has complex tectonic and sedimentary history that encompasses superimposed sub-basins, normal, reverse, and overthrust faulting and areas of uplift.

SC

M AN U

TE D

97

RI PT

73 74 75 76 77 78 79 80 81 82 83 84 85 86 87 88 89 90 91

1.2. Geology of Pakawau Group

The Pakawau Group is a Late Cretaceous megacycle. Its name was first used by Hochstetter (1864) for the Pakawau coal measures, taking the name from the local district. The nomenclature of the group has been used following the use of Thrasher (1992). The lithologies of the Upper Cretaceous source rocks vary between carbonaceous mudstone and coal from alluvial to coastal plain depositional environments with marginal marine influence (Ministry of Business, Innovation and Employment, New Zealand, 2014). The Group is divided into two formations, from oldest to youngest Rakopi and North Cape Formation (Fig. 2).

105 106 107 108 109 110

The Rakopi Formation is the deepest stratigraphic unit which is basin wide distributed. Rakopi Formation is dominated by fluvial to marginal marine lithofacies; the contact between the Rakopi Formation and overlying North Cape Formation marks a significant marine transgression, which is regionally established across the entire basin. North Cape Formation rocks are predominantly marine, transgressive sandstones with siltstone, mudstone, shale and coal layers. In some areas within the basin, this group is more than 2000 m thick. In western

AC C

EP

98 99 100 101 102 103 104

ACCEPTED MANUSCRIPT

parts of the basin at least, the Pakawau Group overlies Palaeozoic and Mesozoic metasedimentary rocks and intrusive that were originally part of Gondwana (Cooper & Tulloch, 1992).

114

2. Samples and methodology

115 116 117 118 119 120 121 122 123 124 125 126 127

Geochemical data and permission to publish results have been obtained from New Zealand Petroleum & Minerals, Ministry of Business, Innovation & Employment, as part of a generous ArcGIS database supplied to the MBIE by GNS (Sykes et al., 2014). A study of geochemical analyses and source rock characterization was done on a total of 286 analyzed samples from the Upper Cretaceous Rakopi (127 samples) and North Cape (159 samples) Formations. The data provided consist of the sample names, associated depths, lithologies and Rock-Eval pyrolysis results. These samples have been obtained from 14 wells (Cape Farewell-1, Cook-1, Fresne-1, Maui-4, Tane-1, Hoki-1, Kiwi-1, Kopuwai-1, Kupe South-4, North Tasman-1, Takapou-1, Taranga-1, Wainui-1 and Tahi-1) and three outcrops from Paturau River, Gentle Annie and Popunga Mine. Lithostratigraphic cross-sections of some of the wells under study are shown in Fig. 3. An additional 25 samples of Rakopi Formation source rocks which have undergone geochemical biomarker analysis are also obtained from three wells (Maui-4, Tane-1 and Cape Farewell-1) in this study for further source rock characterization and depositional environment.

SC

2.1. Analytical Approaches

M AN U

128

RI PT

111 112 113

Table 1 shows a list of the Upper Cretaceous Pakawau Group samples which have been analyzed using Rock-Eval. The dataset have been supplied by the Ministry of Business, Innovation and Employment (MBIE), New Zealand as a part of this research work. The pyrolysis data obtained have been earlier analyzed using Rock-Eval 6 by multiple laboratories and research centers, such as BP Research Centre (1986), US Geological Survey (1991), Geological Survey of Canada (2001, 2002, 2004, 2008) and Applied Petroleum Technology (2010). The vitrinite reflectance values have been measured partly by BP Research Centre (1986), GNS Science (1991, 1996), Newman Energy Research Ltd (2004, 2005, 2006, 2008, 2010), and New Zealand Geological Society. The Pakawau Group source rocks are mostly coal-rich terrestrial sediments deposited in rift-controlled sub-basins (Thrasher, 1992). The lithologies of the samples comprise of coal and mudstone. The measured parameters from pyrolysis include the total organic carbon (TOC) content, S1, S2, S3, hydrogen index (HI), oxygen index (OI) and temperature of maximum pyrolysis yield (Tmax). Vitrinite reflectance (%Ro) data have been obtained for 71 selected samples in the studied wells. %Ro is studied here as a tool for hydrocarbon maturity indicator in source rock, on the basis of its sensitivity to temperature changes.

144 145 146 147

Biomarker characteristics of selected samples are listed in Tables 2, 3 & 4. N-alkanes, m/z-191 and m/z-217 profiles are analyzed and diagnostic biomarker parameters are assessed in this study to identify the different source rock types. The latter include odd-even preference (OEP), carbon preference index (CPI), terrigenous-aromatic ratio (TAR) , waxiness, isoprenoids pristane (Pr)

AC C

EP

TE D

129 130 131 132 133 134 135 136 137 138 139 140 141 142 143

ACCEPTED MANUSCRIPT

152

and phytane (Ph), homohopanes, norhopanes, hopanes, gammacerane, and steranes (C27-C29). Biomarker study is expected to improve the information evaluated from assessments of rock-eval pyrolysis, particularly in terms of confirming the quality or type or organic matter of Pakawau Group. 2.2. Modeling Approaches

RI PT

148 149 150 151

Basin modeling has become a significant technique to understand burial history and thermal assessment of sedimentary basins (Waples, 1980, 1994; Burrus et al, 1991; Shalaby et al., 2011, 2012a, 2012b). Basin modeling has been previously applied in the study area for Rakopi, Farewell, Kaimiro and Mangahewa source rocks (Armstrong et al. 1996; Sarma et al. 2014; Talha Qadri et al. 2016). In this work, quantitative one-dimensional basin modeling is performed to reconstruct the burial, thermal and maturity histories in order to analyze the thermal histories of oil generation and expulsion of the Pakawau Group source rocks and their remaining hydrocarbon potential. The Maui-4 and Tane-1 wells (locations in Fig 1) were modeled using Petromod 1-D (version 9.0) software developed by Schlumberger. The modelling input parameters include events or formations within the chrono-stratigraphy, stratigraphic thicknesses from composite well logs, age of deposition, and lithologies (Tables 5 & 6), as well as, further geochemical parameters such as %TOC and HI. The modeled vitrinite reflectance was calculated by EASY%Ro (Sweeney & Burnham, 1990). The kinetics group, ''Burnham (1989)-TII'', after Burnham (1989), was selected in Petromod to determine the timing of hydrocarbon generation. The modeling results are also calibrated with the available vitrinite reflectance and measured formation temperatures of the studied wells to optimize the thermal history models.

169 170

3. Source Rock Evaluation using Rock Eval-Pyrolysis data 3.1. Potential for Hydrocarbon generation

171 172 173 174 175 176 177 178 179 180 181 182 183 184

Whether a rock can be an effective source rock largely depends on the amount and quality of organic matter, which is demonstrated by the total organic carbon (TOC) content and the pyrolysis S2 yields, respectively. It has been observed that the Upper Cretaceous Pakawau Group is characterized by a wide range and very high total organic carbon (TOC) content 0.64 to 83.3%, indicating mostly excellent source rock in the studied samples. S2 values are from 0.69 to 277 mg HC/g rock, which suggests excellent remaining hydrocarbon generation potential of the sample. Mostly excellent potential yield (S1+S2) values are recorded for the samples analyzed and range between 0.7 to 305 mg HC/g rock. 0.64 to 83.3%, indicating mostly excellent source rock in the studied samples. S2 values are from 0.69 to 277 mg HC/g rock, which suggests excellent remaining hydrocarbon generation potential of the sample. Mostly excellent potential yield (S1+S2) values are recorded for the samples analyzed and range between 0.7 to 305 mg HC/g rock. The hydrocarbon potentiality of the Pakawau Group has been evaluated between TOC and S2 crossplot (Fig. 4). The diagram confirms that most of the assessed samples are in the excellent hydrocarbon potential range.

AC C

EP

TE D

M AN U

SC

153 154 155 156 157 158 159 160 161 162 163 164 165 166 167 168

ACCEPTED MANUSCRIPT

185

3.2. Type of Organic Matter As kerogen matures, the hydrogen content declines as hydrocarbons are expelled from the source rock. As such, hydrogen index plays a significant role in determining the kerogen or organic matter type. The hydrogen index values for the Pakawau Group samples under study are between 59 and 465 mg/g TOC. Based on Peters and Cassa (1994), the hydrogen index for oil-prone Type I kerogen is over 600 mg HC/g TOC, oil-prone Type II is between 300-600 mg HC/g TOC, mixed oil-/gas-prone Type II-III is between 200-300 mg HC/g TOC, gas-prone Type III is 50200 mg HC/g TOC and Type IV is under 50 mg HC/g TOC. Using this classification, most samples are kerogens Type II (145 samples) and mixed Type II-III (118 samples), 23 samples belong to Type III. Individually, Rakopi Formation samples are mostly Type II-III and North Cape Formation samples are mostly type II.

196 197 198 199 200

These results are aligned with the crossplot from the HI (S2/TOC) versus OI (S3/TOC) diagram developed by Espitalié at al. (1985) (Fig. 5), modified after the van Krevelen diagram by Tissot and Welte (1984). It uses the relative amounts of hydrogen and oxygen to determine the kerogen type contained in the source rocks. Most Pakawau Group samples are oil-prone Type II and oil/gas-prone Type II-III kerogens, with few gas-prone Type III.

201 202 203 204 205 206 207 208 209 210 211

New Zealand coals are oil-prone vitrinite-rich and liptinite-poor coals (Killops et al., 1998; Murray et al., 1995; Newman & Newman, 1982; Newman et al., 1997; Norgate et al., 1999). Oilproducing coals are typically liptinite-rich with liptinite concentration of more than 15% (Hunt, 1991). However, according to Wilkins and George (2002), the maceral composition of these New Zealand coals shows that liptinite macerals are not the only most important source of liquid hydrocarbons in certain coals. Perhydrous vitrinites have the potential to generate hydrocarbon liquids in the course of natural coalification. As stated by Wilkins and George (2002), "some liptinites, especially alginite, cutinite and suberinite, contain a higher proportion of the aliphatic content in their structure than other liptinites such as sporinite and resinite and are, therefore, more oil-prone". It has also been observed that the oil-prone coal sequences are recognized as key oil source rocks in at least Southeast Asia, Australia and New Zealand (Fleet & Scott, 1994).

212 213 214 215 216 217 218 219 220

Killops et al. (1994) concluded that extension of the Palaeozoic to middle Cretaceous basement began 80Ma and led to the development of north-northeast trending sub basins (up to 100km long by 30km wide), in which up to 3000m of Late Cretaceous sediments accumulated. These are the terrestrial sediments of the Pakawau Group, which are thicker to the west of the basin and include the coals of the Rakopi Formation. Towards the end of the Cretaceous, a rapid southeast trending marine transgression resulted in the deposition of the mudstones and sandstones of the North Cape Formation, which also constitutes coal measures of Puponga and Wainui members. Therefore, the assessments made in this study are in strong agreement with idea from Killops et al. (1994).

AC C

EP

TE D

M AN U

SC

RI PT

186 187 188 189 190 191 192 193 194 195

ACCEPTED MANUSCRIPT

RI PT

SC

233

As the Pakawau Group is thought to be deposited within fluvial to marginal marine (Browne et al., 2008) depositional environments, reworking of the formation could be sufficient to give rise to an oil-gas prone kerogen (Duval & Janvry, 1992). Coal deposition in Rakopi and North Cape formations may have allowed the preservation of potentially oil-prone organic matter along with allochthonous terrigenous detritus, and deposited in a coastal environment possibly subjected to marine incursions. The main reason for the coals of the Pakawau Group being the dominant Type II-III kerogen could be the possibility of coal being deposited in a fluctuating season water table (i.e., near tidal flat) leading to partial oxidation of accumulated coal. The study also confirms the mixed lithology type from terrestrial and marine origin which is represented by samples from coal, shaly coal and mudstone with the above facts. Fry et al. (2009) noted that variable marine influence throughout the deposition of the coal measures has resulted in pronounced variation in petroleum potential from the Pakawau Group. 3.3. Thermal Maturity Level and Vitrinite Reflectance Measurements (Ro%)

M AN U

221 222 223 224 225 226 227 228 229 230 231 232

Several data types and parameters were used to analyze the organic maturity level. These include vitrinite reflectance data (Ro) and Rock-Eval pyrolysis (Tmax) parameters (Peters & Moldowan, 1993). Generally, vitrinite reflectance values increase with depth due to temperature increment and age of rock (Peters & Cassa, 1994). Vitrinite reflectance values (%Ro) have been obtained for few samples (49 samples) representing the Pakawau Group. The maturation range of Tmax varies for different types of organic matter (Amstrong et al., 1994). In this study, a minimum Tmax value of 430oC considered necessary for thermal maturation of source rocks following previous studies by Barker (1974) and Sykes & Snowdon (2002), with a vitrinite reflectance of 0.55%.

243 244 245 246 247 248 249 250 251

The distribution of pyrolysis Tmax versus vitrinite reflectance (%Ro) plot (Fig. 6) shows that the samples are immature to mature. The Pakawau Group samples has Tmax values 307 to 443oC, indicating immature to early mature stage (Peters & Cassa, 1994), with vitrinite reflectance values range from 0.37 to 0.95% (Table 7). Individually, based on the few selected vitrinite reflectance values, Rakopi Formation source are mature with all values above 0.5%, but the Tmax values show that some points are located within the immature window with Tmax below 430oC (Fig. 6, Table 1). For North Cape Formation source rocks, the Tmax range from 307 to 441oC and the vitrinite reflectance values are from 0.37 to 0.8% (Fig. 6, Table 1), indicating immature to mature samples.

252 253 254 255

The type of hydrocarbon generated can be evaluated according to the plot of PI vs Tmax (Fig. 7). The data are plotted along the margins of the indigenous hydrocarbon generation zone. Samples outside the zone are mostly interpreted as pre to early mature stage as indicated from low Tmax values below 430oC.

256

AC C

EP

TE D

234 235 236 237 238 239 240 241 242

3.4. Source rock characterization and depositional environments

ACCEPTED MANUSCRIPT

Carbon preference index (CPI) and odd-even carbon no. preference (OEP) can indicate maturity of source samples. Values significantly higher or lower than 1.0 suggest low thermal maturity. However, CPI or OEP values equal to 1.0 do not necessarily prove maturity, as these values may also be affected by other processes such as source and biodegradation (Peters et al., 2005). CPI or OEP lower than 1.0 is unusual and may suggest low maturity oils or bitumens from carbonate or hypersaline environments. In the study, OEP and CPI of the studied Rakopi samples range from 1.05 to 1.23 and from 1.05 to 1.43, respectively, as listed in Table 2. These values close to 1.0 indicate that the samples are mature. CPI may also be used as a source indicator of n-alkanes in marine sediments, where n-alkanes derived from land plant epicuticular waxes range from CPI 4 to 10 (Mille et al., 2007). The CPI values under study are between 1.0 and 4.0, which point to n-alkanes of mixed origin.

268 269 270 271 272 273 274 275 276

The terrigenous to aquatic ratio (TAR) is the ratio between the concentration of long chain nalkanes most likely derived from vascular plants (n-C27 + n-C29 + n-C31) to short chain n-alkanes of algal origin (n-C15 + n-C17 + n-C19) and it is used to evaluate the significance in the contribution of terrigenous versus aquatic plants. As listed in Table 2, the TAR values in the study range from 0.09 to 2.62. This wide range of values suggests various source inputs, from terrestrial to marine. Predominance of odd no. C27, C29 and C31 n-alkanes is characteristic of the debris of terrestrial plants (Rieley et al., 1991), and hence TAR value of over 1.0 points to terrestrial source origin (Bourbonniere & Meyers, 1996). However, because algal materials are susceptible to degradation, the TAR values may be affected (Meyers, 2003).

277 278 279 280 281 282 283 284 285 286 287 288 289 290

Isoprenoid alkanes Pristane (Pr) and Phytane (Ph) are common isoprenoid alkanes that are usually derived from phytyl side-chains in chlorophyll. Their high resistance to microbial and thermal degradation makes them suitable as biomarkers for fossil fuels. They are also used to assess the degradation level of petroleum residues, where Pr/Ph ratio more than 1.0 indicates uncontaminated samples, whereas Pr/Ph ratio below 1.0 may have petroleum contamination (Le Dre'au et al., 1997). The Pr/Ph values in the samples are between 2.68 and 10.91 (Table 2). This indicates no contamination with petroleum and non-petroleum origin. According to Hunt (1996), Pr/Ph above 3.0 points to terrestrial source. Accordingly, the Pr/Ph values in this study suggest that the samples are sourced from terrestrial to mixed origin. Pr/C17 and Ph/C18 values are between 0.46 and 8.78 and 0.15 and 1.15, respectively (Table 2). High Pr/C17 and low Ph/C18 values typically indicate terrestrial depositional environment. The wide ranges of values for the ratios suggest various source origins from mixed to terrestrial. The two ratios were plotted in a diagram to determine the depositional environment of the Rakopi Formation source in the wells studied (Fig. 8). Based on this cross-plot, the samples are of non-marine origin.

291 292 293 294

Waxiness is another quantitative indicator used. High waxiness is indicative of terrestrial plants origin. In this study, the waxiness of the studied samples range between 0.49 and 2.73, as listed in Table 2, which suggests various origin source contributions from marine to terrestrial. Most of the samples have waxiness value of above 1.0, which points to dominance in terrestrial origin.

AC C

EP

TE D

M AN U

SC

RI PT

257 258 259 260 261 262 263 264 265 266 267

ACCEPTED MANUSCRIPT

C29 norhopane/C30 hopane values in this study are between 0.44 and 1.38 (Table 3). This range indicates that the organic matter is sourced from a mixed origin. It can be seen that most samples have norhopane to hopane ratio of above 1.0, which points to dominance in terrestrial organic matter. C29/C30 hopanes ratios are generally high (>1) in oils generated from organic rich carbonates and evaporates (Connan et al., 1986).

300 301 302 303 304 305 306 307

The distribution of homohopanes 22R + 22S in organic matter is useful as an indicator of the associated organic matter type, as well as for the evaluation of the oxic or anoxic conditions of source during and immediately after deposition of source sediments (Peters & Moldowan, 1993). The studied samples have a low homohopanes index, which is calculated by the formula H index = C35/(C31-C35), of between ND and 0.04 (Table 3). This suggests an oxic depostion of environment of the oil (Sonibare et al., 2008). C32 homohopane is used as a parameter for maturity. The values are between 0.23 and 0.61 (Table 3), which suggests immature to mature samples. It was noticed that most C32 values are above 0.5, pointing towards oil window.

308 309 310 311

Pr/Ph ratio against C31 homohopane/C30 hopane cross-plot (Fig. 9) is done to determine the source origin, based on the basis that high Pr/Ph values indicate more terrestrial influence, and low C31 homohopane and low homohopane index indicate terrigenous origin. The cross-plot shows dominance of terrestrial source input.

312 313 314 315 316 317

Gammacerane is highly specific for water-column stratification (commonly due to hypersalinity) during source rock deposition (Peters et al., 2005), hence samples with high abundance in gammacerane suggest that the source sediments were deposited in hypersaline lakes (El Nady, 2008). Absent or very low gammacerane peaks corresponds to non-marine source. The study exhibits low concentration of gammacerane for all studied samples, between 0.14 and 0.43 (Table 3), which indicates an oxidizing, non-marine origin.

318 319 320 321 322

C27, C28 and C29 steranes are used as parameters to differentiate depositional settings. Dominance of C27 steranes typically indicates marine-sourced organic matter, whereas dominance of C29 suggests advanced plants input (Peters et al., 2005). Ternary cross-plot diagram between the three steranes (Fig. 10) shows the dominance of C29 steranes, which suggests that the samples are derived from terrestrial organic matter.

323 324 325 326 327 328 329 330 331

C29 steranes are used for maturity in this study of Rakopi source rock of Taranaki Basin. With increasing thermal maturity, C29 20S/(20S+20R) sterane increases from 0-0.5, which in turn causes an increase in C29 ββ/(ββ+αα) sterane values to ~0.7 (Seifert & Moldowan, 1986). This ratio appears to be independent of source organic matter input and thus making it effective at higher levels of maturity (Peters et al., 2005). In this study, C29 20S/(20S+20R) sterane values are from 0.14 to 0.53, whereas C29 ββ/(ββ+αα) sterane value are between 0.17 to 0.53 (Table 4). This indicates that generally the samples are immature to mature, with a greater majority leaning towards mature. Figure 11 shows the relationship between the two parameters, which agrees with more samples being mature than immature. Table 4 also lists down the steranes to hopanes ratio.

AC C

EP

TE D

M AN U

SC

RI PT

295 296 297 298 299

ACCEPTED MANUSCRIPT

In this study, the steranes to hopanes ratio values are low ranging from 0.03 to 0.15, which suggests terrestrial depositional setting.

334 335 336 337 338 339

Based on the assessments of the GC/MS data, it can be concluded that the Rakopi source rock samples are of mixed origin, with major predominance in terrestrial organic matter source. The samples studied showed that the Rakopi Formation source is immature to mature, with the bulk of the assessed samples within the onset of oil window. This is in good agreement with the rockeval pyrolysis assessment of the Rakopi Formation which suggests that the source is oil-prone Type II or oil-/gas-prone Type II-III kerogen.

340 341

4. One-dimensional basin modeling 4.1. Thermal geo-history and paleo-temperature data

342 343 344 345 346 347 348 349 350 351

An understanding of the local subsidence and thermal history is necessary in order to predict the timing of hydrocarbon generation of the Pakawau Group. Heat flow is a better indicator of the thermal state of a sedimentary basin than temperature gradients, as the latter are often affected by regional variations in thermal conductivity due to differing rock types (Peters, 1986). For Taranaki Basin, high quality temperature data has become an effective mode of interpreting the thermal state of the basin. Surface heat flow has been computed along two selected wells (Maui4 and Tane-1). The general interpreted heat flow ranges from 60 to 66 mW/m2 (Fig. 12) (Armstrong et al., 1994; Allis & Shi, 1995); Heat flow is 50-53 mW/m2 in around Tane-1 well which is lower compared to the higher heat flow of ~70 mW/m2 in the north around Maui-4 well (Funnell et al., 1996).

352 353 354 355 356 357 358 359 360 361 362 363 364

This lateral heat flow variation may affect the maturity of potential source rocks within the basin, as heat flow variation of 50-70mW/m2 may result in a difference in depth of about 1 km for the 100oC isotherm (Mackenzie and Quigley, 1988). The variations in present day surface heat flow are thought to be a consequence of various processes affecting previous subsurface temperatures and therefore provide significant constraints in modeling thermal evolution and hydrocarbon generation and expulsion within the basin. Initial thermal conditions were considered to be the consequence of several pre-depositional Mesozoic tectonic events, capped off by rifting affiliated with opening of the Tasman Sea. The deduced heat flow at top basement at the beginning of sedimentation (75 Ma) is 75 mWm-2 and a constant basal heat flow of 39 mWm-2 was used (Amrstrong et al., 1996). In this study, Petromod 1-D version 9.0 has been used to model the burial and thermal histories, as well as to identify the hydrocarbon windows for Maui-4 and Tane-1 wells. An average geothermal gradient and vitrinite reflectance data from the two studied wells were utilized for model calibration.

365 366 367 368

The temperature at a given depth across the Taranaki Basin varied by 30o-40oC, based on borehole temperature (BHT) analyses previously made by Killops et al. (1998), Armstrong et al. (1994) and Allis & Shi (1995). Figures 13 & 14 show the temperature trend line comparison between computed temperature data with the measured data in Maui-4 and Tane-1 wells. In this

AC C

EP

TE D

M AN U

SC

RI PT

332 333

ACCEPTED MANUSCRIPT

study, the BHT values of both wells have been corrected to the effect of circulation to achieve the most optimal temperature, taking into account the researches previously done by Dowdle and Cobb (1975), Armstrong at al. (1994), Waples and Ramly (1995), Funnell et al. (1996) and Peters and Nelson (2012). In this study the initial BHT value of 105oC at the total depth drilled (3839 m) has been corrected to 130oC for Maui-4 well. Tane-1 well BHT value at total depth (4475 m) has been corrected from 116oC to 144oC. From the data, it is evident that corrected measured temperature data has great fit with the computed data in both wells, at all intervals. Funnel et al. (1996) observed that BHT corrections vary from a minimum of about 2-3oC at shallow depths and greater than 20oC at greater depths; uncertainties in the BHT is also to be observed due to the hole sizes. Hence the observation directly matches with the observation made in this study (Peters et al., 2012). Relationship between computed vitrinite reflectance data and observed data has been shown in figures 15 & 16. Both wells show a good fit, which is indicative of well-developed models.

384 385 386 387 388 389 390 391 392 393 394 395 396 397 398 399 400

The burial history for the Maui-4 well (Fig 13) indicates a series of deposition and subsidence. In the Upper Cretaceous (81 to 65 Ma), the burial rate was at 65.6 m/my with a present depositional thickness of 1050 m of the Pakawau Group sediments. Throughout Paleocene, between 65 to 50 Ma, the subsidence slowed down to 39.3 m/my, resulting in a present thickness of 590 m of Farewell Formation. Subsidence up until Early Eocene, around 50 to 33.5 Ma, continued to decrease to 10.3 m/my, with a present thickness of 169 m. This was the Mangahewa Formation. In the following Lower Oligocene (33.5 to 30 Ma), deposition was the slowest at 6.3 m/my for the Turi Formation, resulting to thickness of 22 m. Subsidence rate picked up in the following Up until the Lower Miocene (30 to 21.8 Ma) for Abelhead Formation at 14.4 m/my resulting in a present day thickness of 118 m. Around the Lower Miocene (21.8 to 16 Ma), burial rate was the slowest at a rate of 31.6 m/my, with deposition thickness of 183 m. This was the Manganui Formation. From 16 to 14 Ma in the Middle Miocene, the Moki Formation was deposited at a rate of 189 m/my with a present thickness of 378 m. The Manganui Formation was deposited again overlying the Moki Formation around 14 to 5.3 Ma at 104.3 m/my to a present day thickness of 907 m. Starting from 5.3 to 2.4 Ma (Pliocene), the depression reached was at a rate of 33.8 Ma, with the sedimentation of the Giant Foresets Formation. Its maximum present-day thickness is 33.8 m.

401

5. Burial history and hydrocarbon generation windows

402 403 404 405 406 407

Burial history diagrams are combined with gas and oil window limits for both the studied wells (Figs. 17 & 18). Total drilled depth of Tane-1 well is 4475m, and 3839 m for Maui-4 well. For Maui-4 well (Fig.17), the onset of oil window for Pakawau Group occurred at a depth of 1382 m, at about 61 Ma around the Upper Paleocene, whereas the gas initiated at a depth of 1695m during 54 Ma (Upper Paleocene). Overmature zone was encountered around 2 Ma in the Upper Pliocene, at depth 3712 m. For Tane-1 well (Fig. 18), the Pakawau Group is expected to generate

AC C

EP

TE D

M AN U

4.2. Subsidence and Rate of Deposition

SC

RI PT

369 370 371 372 373 374 375 376 377 378 379 380 381 382 383

ACCEPTED MANUSCRIPT

oil during the Middle Eocene at about 49 Ma at a depth of about 1585 m. Top of gas window occurred at 39 Ma (Upper Eocene) with a depth of 1860m. The bottom of gas window has not been reached in Tane-1 well and it is still producing hydrocarbons.

411 412 413 414 415 416 417 418 419 420 421 422 423 424 425 426

The oil and gas expulsion ratios for Maui-4 and Tane-1 wells are shown in Fig. 19. These models show the relative ratio of hydrocarbon generation between oil and gas, and the ratio is related to kerogen type and maturity. Type II samples are more prone to oil production, Type III samples typically generate hydrocarbon gas and Type II-III samples may generate oil and/or gas. Different maturity levels produce different products: Oil is only produced in “oil window”, while hydrocarbon gas is expelled within the higher temperature “gas and condensate” zone. Following this relationship, figure 19 for Maui-4 well shows a higher proportion of oil generation relative to gas for the Pakawau Group source rocks. For example, at 14 Ma, the quantity of oil produced was 36 mg HC/g TOC, compared to gas at 7 mg HC/g TOC. Tane-1 well also shows a higher quantity of oil production of 12 mg HC/g TOC against gas production of 2 mg HC/g TOC, at 4 Ma. To the present day, 97 mg oil/g TOC and 70 mg oil/g TOC have been expelled in Maui-4 and Tane-1 wells, respectively. The results confirm the previous analyses and discussions about kerogen type and associated hydrocarbon products of the Pakawau Group source rocks under study, that they largely contain oil-prone Type II or Type II-III kerogen. The results also imply that this basin is a relatively younger basin in which hydrocarbon is still being expelled from the source rock without attaining peak generation.

427 428 429 430 431

Additionally, a simplified petroleum system event chart has been built for Tane-1 and Maui-4 wells under study to show the temporal relation of the essential petroleum elements and processes (Fig. 20). The hydrocarbon production has not reached its peak and is still generating oil and gas to the present day. The folding/thrusting event which occurred in the Lower Neogene (22 to 10 Ma) provided trap for the Pakawau Group source rocks.

432

6. Conclusions

433 434 435 436 437 438 439 440 441 442 443 444

The Upper Cretaceous Pakawau Group is one of the most important hydrocarbon source rocks in Taranaki Basin, New Zealand. Analyzed samples have been collected from the Rakopi and North Cape formations for geochemical characteristics study, and it was observed that the Pakawau Group source contains mostly Type II and Type-II-III kerogen with Hydrogen Index (HI) values ranging from 59 to 465 mg/g TOC; this wide range is highly indicative of variably mixed gas and oil prone to oil prone kerogen types. This is also conformable with the presence of terrestrial and marine origin of source rock samples as indicated by the biomarker characteristics assessments of Rakopi source made in this study. Vitrinite reflectance data shows that the Pakawau Group source is in immature to mature oil window for hydrocarbon generation having vitrinite reflectance values ranging generally between 0.37% to 0.95% Ro and Tmax values from 307 to 443oC. This is again supported by the biomarker parameters homohopanes and steranes. Burial history modelling on this formation indicates that the Upper Cretaceous Pakawau Group

AC C

EP

TE D

M AN U

SC

RI PT

408 409 410

ACCEPTED MANUSCRIPT

entered mature to mid mature stages for hydrocarbon generation during the Upper Paleocene to Middle Eocene.

447

6. Acknowledgements

448 449 450 451 452 453 454

The authors would like to thank Ministry of Business. Innovation & Employment (MBIE), New Zealand for providing the dataset for the research. The authors are grateful to the Department of Geological Sciences, Universiti Brunei Darussalam for supporting with the technical and administrative facilities required to complete the research. Schlumberger is greatly acknowledged for providing us Petromod which we utilized for basin modelling. Special thanks goes to Richard Sykes for his valuable suggestions on the dataset and Kenneth Peters for his guidance.

SC

RI PT

445 446

AC C

EP

TE D

M AN U

455

ACCEPTED MANUSCRIPT

REFERENCES

457 458

Allis, R.G., Shi, Y. 1995. New insights to temperature and pressure beneath the central Southern Alps, New Zealand. New Zealand Journal of Geology & Geophysics, 38(4): 585-592.

459 460 461

Analabs.1984. Petroleum Geochemistry of the Taranaki Basin. Ministry of Business, Innovation and Employment, New Zealand, Unpublished Petroleum Report, 1013. https://data.nzpam.govt.nz/GOLD/system/mainframe.asp.

462 463 464

Armstrong, P.A., Chapman, D.S., Funnell, R.H., Allis, R.G., Kamp, P.J.J. 1994. Thermal state, thermal modelling, and hydrocarbon generation in the Taranaki Basin, New Zealand. New Zealand Petroleum Conference Proceedings, 289-307.

465 466 467

Armstrong, P.A., Chapman, D.S., Funnell, R.H., Allis, R.G., Kamp, P.J.J., 1996. Thermal modeling and hydrocarbon generation in an active-margin basin: Taranaki Basin, New Zealand. AAPG Bulletin, 80(8): 1216–1241.

468 469

Barker, C. 1974. Pyrolysis techniques for source-rock evaluation. AAPG Bulletin, 58: 23492361.

470 471 472

Baur, J., Sutherland, R., Stern, T., 2014.Anomalous passive subsidence of deep-water sedimentary basins: a prearc basin example, southern New Caledonia Trough and Taranaki Basin, New Zealand. Basin Research, 26: 242–268.

473 474 475

Bourbonniere, R.A., Meyers, P.A. 1996. Sedimentary geolipid records of historical changes in the watersheds and productivities of Lakes Ontario and Erie. Limnol. Oceanography, 41: 352359.

476 477 478 479

Browne, G.H., Kennedy, E.M., Constable, R.M., Raine, J.I., Crouch, E.M., Sykes, R. 2008. An outcrop-based study of the economically significant Late Cretaceous Rakopi Formation, northwest Nelson, Taranaki Basin, New Zealand. New Zealand Journal of Geology & Geophysics, 51: 295–315.

480 481

Burnham, A. 1989. A simple kinetic model of petroleum formation and cracking.(No.UCID21665). Lawrence Livermore National Lab., CA (USA).

482 483 484

Burrus, J., Kuhfuss, A., Doligez, B., Ungerer, P. 1991.Are numerical models useful in reconstructing the migration of hydrocarbons? A discussion based on the Northern Viking Graben. Geological Society, London. Special Publications, 59: 89-109.

485 486 487

Collier, R.J., Johnston, J.H. 1991. The identification of possible hydrocarbon source rocks, using biomarker geochemistry in the Taranaki Basin, New Zealand. Journal of Southeast Asian Earth Sciences, 5(1-4): 231-239.

AC C

EP

TE D

M AN U

SC

RI PT

456

ACCEPTED MANUSCRIPT

Connan, J., Bouroullec, J., Dessort, D., Albrecht, P. 1986. The macrobial input in carbonateanhydrite facies of a sabkha paleoenvironment from Guatemala: a molecular approach. Organic Geochemistry, 10: 29-50.

491 492

Cooper, R.A., Tulloch, A.J., 1992. Early Palaeozoic terrenes in New Zealand and their relationship to the Lachlan Fold Belt. Tectonophysics, 214(1):, 129-144.

493 494

Dowdle, W.L., Cobb, W.M. 1975. Static formation temperature from well logs—an empirical method. Journal of Petroleum Technology, 27: 1322–1330.

495 496

Duval B.C., Janvry C., Loiret B. Detailed geoscience reinterpretation of Indonesia's Mahakam Delta scores. Oil & Gas Journal, 1992, 90 (22): 67-72.

497 498 499

El Nady, M.M. 2008. Biomarkers assessment of crude oils and extracts from JurassicCretaceous rocks, North Qattara Depression, North Western Desert, Egypt. Journal of Petroleum Science and Technology, 26: 1063-1080.

500 501

Espitalié, J., Madec, M., Tissot, B., Mennin, J., Leplat, P. 1977. Sourcerock characterization method for petroleum exploration. Ninth Annual Offshore Conference Proceedings, 3: 439-448.

502 503

Fleet, A.J., Scott, A.C. 1994. Coal and coal-bearing strata as oil-prone source rocks: an overview. Geological Society, London, Special Publications, 77(1): 1-8.

504 505 506 507

Fry, J.C., Horsfield, B., Sykes, R., Cragg, B.A., Heywood, C., Kim, G.T., Mangelsdorf, K., Mildenhall, D.C., Rinna, J., Vieth, A., Zink, K.G. 2009. Prokaryotic populations and activities in an interbedded coal deposit, including a previously deeply buried section (1.6–2.3 km) above∼ 150 Ma basement rock. Geomicrobiology Journal, 26(3): 163-78.

508 509

Funnell, R., Chapman, D., Allis, R., Armstrong, P. 1996. Thermal state of the Taranaki basin, New Zealand. Journal of Geophysical Research: Solid Earth, 101(11): 25197-25215.

510 511

Hochstetter, F.V. 1864. Geologie von Neu-Seeland. Vienna, Edited by: Fleming, C.A. Wellington: Government Printer, 320.

512 513

Huang, W.Y., Meinschein, W.G. 1979. Sterols as ecological indicators. Geochimet Chosmochim Acta, 43: 739-45.

514 515

Hunt, J. 1991. Generation of gas and oil from coal and other terrestrial organic matter. Organic Geochemistry, 17: 673-680.

516 517

Hunt, J. 1996. Petroleum Geochemistry and Geology. New York: Freeman and Company, p. 743.

AC C

EP

TE D

M AN U

SC

RI PT

488 489 490

ACCEPTED MANUSCRIPT

Jumat, N., Shalaby, M.R., Islam, M.A. 2017. An integrated source rock characterization using geochemical analysis and well logs: a case study of Taranaki Basin, New Zealand. Petroleum and Coal, 59(6): 884-910.

521 522 523 524

Kamp, P.J.J., Vonk, A.J., Bland, K.J., Hansen, R.J., Hendy, A.J.W., McIntyre, A.P., Ngatai, M., Cartwright, S,J., Hayton, S., Nelson, C.S. 2004. Neogene stratigraphic architecture and tectonic evolution of Wanganui, King Country, and eastern Taranaki Basins, New Zealand. New Zealand Journal of Geology and Geophysics, 47(4): 625-644.

525 526

Killops, S.D., Frewin, N.L. 1994. Triterpenoiddiagenesis and cuticular preservation. Organic Geochemistry, 21(12): 1193-1209.

527 528 529

Killops, S.D., Funnell, R.H., Suggate, R.P., Sykes, R., Peters, K.E., Walters, C.,Woolhouse A.D., Weston R.J., Boudou J.P. 1998. Predicting generation and expulsion of paraffinic oil from vitrinite-rich coals. Organic Geochemistry, 29(1-3): 1-21.

530 531

Killops, S.D., Woolhouse, A.D., Weston, R.J., Cook, R.A. 1994. A geochemical appraisal of oil generation in the Taranaki Basin, New Zealand. AAPG Bulletin, 78: 1560–1585.

532 533

King, P. R., Thrasher, G.P. 1996. Cretaceous-Cenozoic geology and petroleum systems of theTaranaki Basin, New Zealand .Institute of Geological & Nuclear Sciences monograph, 13.

534 535 536

Kroeger, K., Funnell, R., Nicol, A., Fohrmann, M., Bland, K., King, P., 2013. 3D crustal-scale heat-flow regimes at a developing active margin (Taranaki Basin, New Zealand). Tectonophysics, 591: 175–193.

537 538

Mackenzie, A.S., & Quigley, T.M. 1988. Principles of geochemical prospect appraisal. AAPG Bulletin, 72: 399–415.

539 540

Meyers, P.A. 2003. Application of organic geochemistry to paleolimnological reconstruction: a summary of examples from the Laurentian Great Lake. Organic Geochemistry, 34(2): 261-289.

541 542 543

Ministry of Business, Innovation and Employment, New Zealand, 2014. New Zealand Petroleum Basins 2014/2015 Revised edition. Wellington: New Zealand Petroleum & Minerals, 105pp.

544 545 546

Murray, A.P., Summons, R.E., Boreham, J., Dowling, L.M., 1994. Biomarker and n-alkane isotope profiles for Tertiary oils: relationship to source rock depositional setting. Organic Geochemistry, 22(3-5): 521.

547 548 549

Newman, J, Newman, N. 1982. Reflectance anomalies in Pike River coals: evidence of variability in vitrinite type, with implications for maturation studies and "Suggate rank", New Zealand Journal of Geological Geophysics, 25: 233-243.

AC C

EP

TE D

M AN U

SC

RI PT

518 519 520

ACCEPTED MANUSCRIPT

Newman, N.A., Moore, T.A., Esterle, J.S. 1997. Geochemistry and petrography of the Taupiri and Kupakupa coal seams, Waikato coal measures (Eocene), New Zealand. International Journal of Coal Geology, 33(2): 103-33.

553 554 555

Norgate, C.M., Boreham, C.J., Wilkins, A.J. 1999.Changes in hydrocarbon maturity indices with coal rank and type, Buller Coalfield, New Zealand. Organic Geochemistry, 30(8): 9851010.

556 557

Palmer, J. 1985. Pre-Miocene lithostratigraphy of Taranaki Basin, New Zealand. New Zealand Journal of Geology and Geophysics, 28: 197–216.

558

Palmer, J., Geoff, B., 1988. Taranaki Basin, New Zealand. Active Margin Basins, 269–290.

559 560

Peters, K.E., Cassa, M.R. 1994. Applied source rock geochemistry. In: Magoon, L., & Dow, W.G. (Eds). The petroleum system - from source to trap: AAPG Memoir, 60: 93-120.

561 562

Peters, K.E., Fraser, T.H., Amris, W., Rustanto, B., & Hermanto, E. 1999. The Geochemistry of crude oils from eastern Indonesia. AAPG Bulletin, 83: 1927-1942.

563 564

Peters, K.E., Moldowan, M.J. 1993. The biomarker guide: interpreting molecular fossils in petroleum and ancient sediments (Book Series): 80-100.

565 566 567 568

Peters, K.E., Nelson, P.H. 2012.Criteria to determine borehole formation temperatures for calibration of basin and petroleum system model. SEPM Special Publication No. 103, 2012, SEPM (Society for Sedimentary Geology), Print ISBN978-1-56576-315-9, CD/DVD ISBN 9781-56576-317-3, p. 5–15.

569 570

Peters, K.E., Walters, C.C., Moldowan, J.M. 2005. The Biomarker Guide, 2nd ed. Cambridge: Cambridge University Press, p. 1155.

571 572 573

Pilaar, W.F.H., Wakefield, L.L., 1978. Structural and stratigraphic evolution of the Taranaki Basin, offshore North Island, New Zealand. Australian Petroleum Production and Exploration Association Journal, 18: 93–101.

574 575 576

Rieley, G., Collier, R.J., Jones, D.M., Eglinton, G. 1991. The biogeochemistry of Ellesmere Lake, UK I: source correlation of leaf wax inputs to the sedimentary record. Organic Geochemistry, 17: 901-912.

577 578 579

Sarma, M., Kellet, R., Pryde, S., Reynolds, G. 2014. Petroleum Systems Modelling: Charge Evaluation of the Eltham Area (PEP 51150), Onshore Taranaki Basin: New Zealand Energy Corp, Wellington, New Zealand, 6 p.

580 581 582

Seifert, W.K., Moldowan, J.M. 1986. Use of biological biomarkers in petroleum exploration, in: Johns, R.B. (ed.), Methods in Geochemistry and Geophysics 24. Amsterdam: Elsevier, pp. 261-290.

AC C

EP

TE D

M AN U

SC

RI PT

550 551 552

ACCEPTED MANUSCRIPT

Shalaby, M.R., Hakimi M.H., Abdullah, W.H. 2011. Geochemical characteristics and hydrocarbon generation modeling of the Jurassic source rocks in the Shoushan Basin, north Western Desert, Egypt. Marine and Petroleum Geology, 28: 1611-1624.

586 587 588

Shalaby, M.R., Hakimi M.H., Abdullah, W.H. 2012a. Modeling of gas generation from the Alam El-Buieb Formation in the Shoushan Basin, northern Western Desert of Egypt. International Journal of Earth Sciences, 102: 319-332.

589 590 591

Shalaby, M.R., Hakimi M.H., Abdullah, W.H. 2012b. Organic geochemical characteristics and interpreted depositional environment of the Khatatba Formation, northern Western Desert, Egypt. AAPG Bulletin, 96(11): 2019-2036.

592 593

Sonibare, O., Alimi, H., Jarvie, D., Ehinola, O.A. 2008.Origin and occurrence of crude oil in the Niger Delta, Nigeria. Journal of Petroleum Science and Engineering, 61: 97–107.

594 595

Sweeney, J.J., Burnham, A.K. 1990. Evaluation of a Simple Model of Vitrinite Reflectance Based on Chemical Kinetics. AAPG Bulletin, 74(10): 1559-1570.

596 597 598 599 600

Sykes, R., Scadden, P.G., Martin, C., Collier, T.J., Bland, K.J., Griffin, A.G., Strogen, D.P. 2014. An ArcGIS project on petroleum source rock potential and maturity in New Zealand basins. GNS Science Consultancy Report 2014/244, 16. https://www.nzpam.govt.nz/cms/investors/ourresourcepotential/petroleum/orderdatapack/fg_base_view_p3.

601 602

Sykes R., Snowden, L.R. 2002. Guidelines for assessing the petroleum potential of coaly source rocks using Rock-Eval pyrolysis. Organic Geochemistry, 33: 1441-1455.

603 604 605

Talha Qadri S.M., Shalaby M.R., Islam, M.A., Hoon, L.L. 2016. Source rock characterization and hydrocarbon generation modeling of the Middle to Late Eocene Mangahewa Formation in Taranaki Basin, New Zealand. Arabian Journal of Earth Sciences, 9(10): 559.

606 607

Thrasher, G.P., Paul, G. 1992. Last Cretaceous Geology of Taranaki Basin, New Zealand. Unpublished PhD thesis, Victoria University of Wellington, Research Archive.

608 609

Tissot, B.P., Welte, D.H.. 1984. Petroleum Formation and Occurrence, 2nd Edition. Berlin: Springer-Verlag.

610 611

Uruski, C. 2008. Deepwater Taranaki, New Zealand: structural development and petroleum potential. Exploration Geophysics, 39(2): 94-107

612 613

Waples, D.W. 1980. Time and Temperature in Petroleum Formation: Application of Lopatin's Method to Petroleum Exploration. AAPG Bulletin, 2(6): 916-926.

614 615

Waples, D.W. 1994. Maturity Modeling: Thermal Indicators, Hydrocarbon Generation, and Oil Cracking. AAPG Memoir, 60: 285-306.

AC C

EP

TE D

M AN U

SC

RI PT

583 584 585

ACCEPTED MANUSCRIPT

Waples, D., Ramly, M. 1995. A simple statistical method for correcting and standardizing heat flows and subsurface temperatures derived from log and test data. Bulletin of the Geological Society of Malaysia, Special Publication, 37: 253-267.

619 620

Wilkins, R.W, George, S.C. 2002. Coal as a source rock for oil: a review. International Journal of Coal Geology, 50(1): 317-361.

RI PT

616 617 618

AC C

EP

TE D

M AN U

SC

621

ACCEPTED MANUSCRIPT

TABLES (with captions) Table 1: Rock-Eval pyrolysis data for Pakawau Group source rock samples under study.

Paturau River

Coal Coal Coal Coal Coal Coal Coal Coal Coal Coal Mudstone Bulk coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Bulk coal Mudstone Bulk coal Mudstone Bulk coal Mudstone Bulk coal Mudstone Bulk coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Coal Coal Shaly coal Mudstone Coal

Cape Farewell-1

Cook-1

Fresne-1

AC C

EP

Maui-4

Tahi-1 Tane-1

Rock Sample Outcrop Outcrop Outcrop Outcrop Outcrop Outcrop Outcrop Outcrop Outcrop Outcrop Outcrop Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings

S1

S2

S3

Tmax

HI

OI

TOC

PI

S1+S2

2.1 4.2 2.6 3.1 3.7 2.8 4.4 4.1 3.9 4.2 1.7 1.3 0.2 9.9 4.8 0.8 16.3 9.2 5.6 3.2 0.3 2.1 1.0 7.9 0.2 4.3 1.0 13.9 0.3 9.7 6.0 2.4 10.0 3.1 0.7 2.8 2.3 0.6 2.7 1.5 9.8 4.2 0.9 10.5 3.6 1.2 1.5 0.7 9.7 4.2 0.7 3.7

119.7 190.2 139.2 164.0 206.7 171.5 231.6 213.3 223.4 238.6 117.7 54.4 12.6 216.4 128.0 20.7 254.0 126.8 46.7 109.2 17.8 85.1 36.7 126.1 9.6 135.6 39.6 175.6 5.4 130.7 48.5 18.2 139.1 58.4 12.0 111.5 71.5 21.2 116.4 52.1 204.6 87.3 18.2 218.9 74.5 20.5 103.9 43.4 225.0 104.7 34.3 149.2

9.9 9.7 12.6 13.8 7.6 9.2 7.6 8.3 8.6 7.9 3.7 17.9 0.8 7.3 3.0 0.7 3.1 1.2 0.4 5.5 0.8 4.6 1.1 9.3 0.5 6.3 1.5 2.1 0.2 12.8 6.8 1.8 13.8 7.4 1.2 12.7 4.8 1.6 12.0 4.4 7.2 3.8 1.1 4.9 1.5 0.9 23.2 25.1 10.6 5.9 1.5 11.4

425 425 427 424 424 426 427 425 426 426 424 425 428 421 422 423 435 436 436 425 426 428 427 428 431 427 431 443 443 423 429 425 422 426 422 428 427 427 428 428 430 430 431 441 438 438 418 419 421 421 417 429

217 273 215 237 282 270 318 305 307 350 361 95 325 333 376 301 368 386 359 323 341 279 365 201 267 292 326 310 191 158 193 219 214 228 217 163 252 266 168 170 290 257 238 294 261 253 193 84 326 288 310 212

18 14 19 20 10 14 10 12 12 12 11 31 21 11 9 10 4 4 3 16 15 15 11 15 13 13 12 4 5 15 27 22 21 29 21 18 17 20 17 14 10 11 14 7 5 11 43 48 15 16 13 16

55.6 70.2 65.4 69.7 73.8 64.0 73.2 70.4 73.1 68.4 32.8 57.7 3.9 65.3 34.2 6.9 69.4 33.0 13.1 34.0 5.2 30.6 10.1 63.2 3.6 46.7 12.2 57.0 2.9 83.3 25.3 8.4 65.6 25.8 5.6 69.1 28.6 8.0 69.9 30.9 70.9 34.2 7.7 74.9 28.7 8.2 54.2 52.1 69.2 36.5 11.1 70.7

0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.02 0.01 0.02 0.01 0.04 0.04 0.04 0.06 0.07 0.11 0.03 0.02 0.02 0.03 0.06 0.02 0.03 0.02 0.07 0.06 0.07 0.11 0.12 0.07 0.05 0.06 0.02 0.03 0.03 0.02 0.03 0.05 0.05 0.05 0.05 0.05 0.05 0.01 0.01 0.04 0.04 0.02 0.02

121.8 194.5 141.9 167.1 210.4 174.4 236.0 217.4 227.4 242.9 119.4 55.7 12.7 226.3 132.8 21.4 270.3 136.0 52.2 112.4 18.1 87.2 37.6 134.0 9.8 139.9 40.6 189.5 5.8 140.4 54.5 20.6 149.1 61.5 12.7 114.3 73.8 21.8 119.1 53.5 214.4 91.5 19.1 229.4 78.1 21.7 105.4 44.0 234.7 108.9 35.0 152.9

RI PT

Rakopi

Depth (m) 0 0.22 0.84 1.29 1.87 2.36 3.04 3.66 4.39 4.99 5.28 230 230 1240 1240 1240 2390 2390 2390 2390 2390 2576 2576 1043 1043 1202 1202 2489 2489 2158 2158 2158 2200.7 2200.7 2200.7 2502.4 2502.4 2502.4 2667 2667 3285.7 3285.7 3285.7 3819.1 3819.1 3819.1 1591 1732 3637 3637 3637 3664

SC

Lithology

M AN U

Location/Well

TE D

Formation

ACCEPTED MANUSCRIPT

AC C

103.9 23.8 18.4 171.8 6.5 142.0 169.1 100.6 143.0 97.4 171.8 106.4 33.2 14.9 2.8 176.0 68.8 6.4 20.1 51.1 198.9 132.2 26.7 214.4 98.4 38.5 231.1 108.3 44.0 203.5 101.3 32.2 221.3 91.9 27.7 191.6 105.5 31.8 226.4 112.4 13.2 185.3 100.4 35.4 199.5 110.3 28.9 201.6 93.5 28.7 182.9 99.1 22.2 204.0 98.6 32.9 215.3 109.7 41.1

6.3 1.5 0.6 10.4 0.3 11.9 10.9 4.7 10.1 4.7 10.2 4.8 1.6 1.0 0.5 9.7 4.2 0.7 0.9 2.0 6.3 3.9 0.8 5.6 1.1 0.8 4.8 1.6 0.8 5.3 2.3 0.9 5.3 2.1 1.1 4.7 2.6 0.7 5.6 2.9 0.1 2.9 2.0 0.8 5.0 1.1 0.6 4.4 2.2 0.6 4.0 2.9 0.5 3.7 1.3 0.7 4.0 1.5 0.8

425 427 430 425 427 427 428 427 423 426 424 427 430 427 433 423 416 430 428 425 424 428 428 428 428 428 430 430 429 432 432 426 432 432 430 433 433 432 434 432 440 434 433 433 432 434 433 434 431 433 437 436 434 435 435 434 435 437 437

283 269 391 258 297 205 252 306 228 300 259 316 297 226 127 255 225 142 288 276 308 329 347 308 336 369 325 318 348 282 295 299 294 288 269 279 292 273 313 299 261 296 297 303 278 296 286 276 283 294 258 239 276 280 287 282 305 307 309

17 17 12 15 15 17 16 14 16 15 15 14 15 15 21 14 14 15 12 11 10 10 10 8 4 7 7 5 7 7 7 8 7 6 11 7 7 6 8 8 1 5 6 7 7 3 6 6 7 6 6 7 6 5 4 6 6 4 6

36.9 8.9 4.7 66.9 2.2 69.9 67.4 33.1 63.1 32.6 66.7 33.8 11.2 6.6 2.2 69.4 30.7 4.5 7.0 18.6 64.9 40.3 7.7 70.1 29.5 10.5 71.5 34.2 12.7 72.5 34.5 10.8 75.8 32.1 10.4 69.1 36.3 11.7 72.6 37.8 5.1 62.9 34.0 11.7 72.2 37.5 10.2 73.6 33.2 9.8 71.5 41.8 8.1 73.4 34.6 11.7 71.1 35.9 13.4

RI PT

2.4 0.3 0.4 5.2 0.1 4.0 4.6 2.1 4.0 2.2 6.1 2.8 0.5 0.2 0.1 10.9 3.7 0.2 0.5 2.0 12.6 7.4 1.0 14.3 6.8 2.1 16.0 6.8 2.1 12.7 4.4 1.3 12.7 4.2 1.0 12.2 5.6 1.8 14.5 6.7 1.0 11.9 5.3 1.7 13.9 6.1 1.6 15.2 6.5 1.6 12.0 6.4 1.0 17.6 7.4 2.4 14.6 6.4 3.2

SC

Cuttings Cuttings Core Core Core Core Core Core Core Core Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings

M AN U

3664 3664 3686.6 3687.48 3688.12 3688.73 3689.31 3689.31 3690.42 3690.42 3709 3709 3709 3763 3826 3871 3871 3871 3934 3946 3994 3994 3994 4006 4006 4006 4018 4018 4018 4066 4066 4066 4075 4075 4075 4108 4108 4108 4120 4120 4120 4138 4138 4138 4168 4168 4168 4198 4198 4198 4225 4225 4225 4258 4258 4258 4276 4276 4276

TE D

Shaly coal Mudstone Mudstone Coal Mudstone Coal Coal Shaly coal Coal Shaly coal Coal Shaly coal Mudstone Mudstone Mudstone Coal Shaly coal Mudstone Mudstone Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone

EP

Tane-1

0.02 0.01 0.02 0.03 0.02 0.03 0.03 0.02 0.03 0.02 0.03 0.03 0.01 0.02 0.03 0.06 0.05 0.03 0.02 0.04 0.06 0.05 0.04 0.06 0.06 0.05 0.06 0.06 0.05 0.06 0.04 0.04 0.05 0.04 0.04 0.06 0.05 0.05 0.06 0.06 0.07 0.06 0.05 0.05 0.06 0.05 0.05 0.07 0.06 0.05 0.06 0.06 0.04 0.08 0.07 0.07 0.06 0.05 0.07

106.3 24.0 18.8 177.0 6.6 146.0 173.6 102.8 146.9 99.6 178.0 109.2 33.6 15.1 2.9 186.9 72.5 6.6 20.6 53.1 211.4 139.6 27.7 228.7 105.2 40.6 247.1 115.0 46.1 216.2 105.7 33.5 234.0 96.1 28.7 203.8 111.1 33.6 240.9 119.1 14.1 197.2 105.6 37.1 213.4 116.5 30.6 216.8 100.0 30.3 194.9 105.5 23.2 221.6 106.0 35.3 229.9 116.1 44.3

ACCEPTED MANUSCRIPT

Fresne-1

EP

Cape Farewell-1

Kiwi-1

15.3 5.5 2.3 10.1 5.7 0.6 11.2 6.5 0.5 16.0 7.7 3.0 13.6 7.1 2.8 5.5 14 3.5 20.9 17.8 3.6 2.5 18.8 3.8 21.6 2.9 27.1 12.4 4.4 25.7 10.8 5.3 25.4 9.6 5.2 11.9 2.8 16.1 2 1.5 3.06 1.27 0.15 7.91 0.16 4.31 0.95 27.83 18.03 1.1 29.32 15.54 4.97 0.82 29.61 15.18 6.42 1.42 27.26

223.9 108.9 36.1 202.8 100.8 16.4 189.3 98.6 13.7 180.0 102.1 38.6 176.8 105.1 36.1 143.7 132.2 41 249.5 175.8 39.9 30.6 237.6 44.5 212.7 35.2 272.8 114.1 53.6 237.6 107.1 56.9 225.6 98 57.3 153.5 41.7 159.1 32.9 22 36.91 54.44 12.59 126.06 9.64 135.57 39.63 277.16 130.1 3.15 260.49 136.15 35.88 2.43 264.23 122.86 49.1 3.37 272.81

2.9 1.5 0.5 5.6 2.1 0.4 5.9 1.9 0.3 3.9 2.6 0.7 3.5 2.6 0.6 12.2 29.6 1.1 6.4 3.3 3.5 1.4 8.5 1 4.3 2.5 3.4 5.3 2.1 7.7 6.5 4.2 2.9 5.8 3.1 14.1 7.1 1.3 2.7 2.5 43.96 37.27 0.83 14.97 0.82 6.65 1.67 1.49 1.13 0.44 1.15 0.89 0.33 0.44 1.09 1.16 0.23 0.5 1.07

436 437 437 430 433 433 433 431 436 439 439 435 439 435 439 425 411 419 414 412 420 420 415 418 414 420 414 414 419 414 419 420 414 419 424 415 422 415 426 423 424 425 428 428 431 427 431 421 418 312 422 424 426 310 427 421 425 307 424

308 342 338 275 319 279 256 294 279 256 267 288 250 271 283 220 332 398 417 361 376 392 401 405 353 396 369 385 416 343 368 415 339 366 424 271 421 384 387 423 59 94 324 199 266 290 324 404 391 350 390 448 431 289 379 440 447 330 401

4 5 5 8 7 6 8 6 6 5 7 5 5 7 5 19 74 11 11 7 33 18 14 9 7 28 5 18 16 11 22 31 4 22 23 25 72 3 32 48 70 65 21 24 23 14 14 2 3 49 2 3 4 52 2 4 2 49 2

73.0 32.0 10.7 74.3 31.7 5.9 74.5 33.7 4.9 70.7 38.5 13.5 71.1 39.0 12.9 65.8 39.8 10.3 59.9 48.7 10.6 7.8 59.3 11 60.3 8.9 74 29.6 12.9 69.2 29.1 13.7 66.6 26.8 13.5 56.6 9.9 41.4 8.5 5.2 62.41 57.72 3.89 63.24 3.62 46.68 12.22 68.63 33.29 0.9 66.78 30.37 8.33 0.84 69.75 27.91 10.98 1.02 68.05

RI PT

Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Core Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings

SC

4306 4306 4306 4360 4360 4360 4384 4384 4384 4396 4396 4396 4408 4408 4408 3709 3500 3500 3480 3505 3480 3505 3495 3495 3510 3510 3515 3515 3515 3520 3520 3520 3525 3525 3525 3530 3530 3535 3535 3585 0 230 230 1043 1043 1202 1202 4165 4165 4165 4170 4170 4170 4170 4175 4175 4175 4175 4180

TE D

Hoki-1

AC C

North Cape

Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Coal Coaly mudstone Coal Coal Coaly mudstone Coaly mudstone Coal Coaly mudstone Coal Coaly mudstone Coal Shaly coal Coaly mudstone Coal Shaly coal Coaly mudstone Coal Shaly coal Coaly mudstone Coal Coaly mudstone Coal Coaly mudstone Coaly mudstone Coal Coal Mudstone Coal Mudstone Coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Mudstone Coal Shaly coal Mudstone Mudstone Coal

M AN U

Tane-1

0.06 0.05 0.06 0.05 0.05 0.03 0.06 0.06 0.04 0.08 0.07 0.07 0.07 0.06 0.07 0.04 0.10 0.08 0.08 0.09 0.08 0.08 0.07 0.08 0.09 0.08 0.09 0.10 0.08 0.10 0.09 0.09 0.10 0.09 0.08 0.07 0.06 0.09 0.06 0.06 0.08 0.02 0.01 0.06 0.02 0.03 0.02 0.09 0.12 0.26 0.10 0.10 0.12 0.25 0.10 0.11 0.12 0.30 0.09

239.2 114.4 38.3 212.9 106.5 16.9 200.6 105.1 14.2 196.0 109.8 41.6 190.3 112.1 38.9 149.2 146.2 44.5 270.4 193.6 43.5 33.1 256.4 48.3 234.3 38.1 299.9 126.5 58.0 263.3 117.9 62.2 251.0 107.6 62.5 165.4 44.5 175.2 34.9 23.5 40.0 55.7 12.7 134.0 9.8 139.9 40.6 305.0 148.1 4.3 289.8 151.7 40.9 3.3 293.8 138.0 55.5 4.8 300.1

ACCEPTED MANUSCRIPT

North Tasman-1

AC C

EP

Takapou-1

Taranga-1

15.14 4.73 1.44 28.46 13.88 6.42 1.56 27.43 14.61 6.42 1.35 20.68 15.31 0.77 0.56 5.22 0.57 0.62 2.22 2.17 0.18 6.21 3.16 0.62 5.99 3.32 0.88 9.59 5.2 0.84 5.2 5.5 5.3 14.91 4.54 18.18 11.62 3.48 13.23 3.3 18.57 12.35 3.27 13.32 3.71 15.54 11.65 4.87 14.12 9.8 4.56 15.54 9.96 4.1 16.26 8.38 2.27 21.9 12

140.23 39.36 3.27 271.28 126.88 51.61 3.33 274.19 129.51 48.13 2.88 203.13 142.85 5.03 2.5 49.11 2.65 2.13 92.82 82.95 14.7 187.35 106.46 27.09 182.3 102.39 31.59 222.69 128.5 31.54 216.9 240 182 143.31 38.51 247.73 116.36 32.89 134.9 35.78 217.18 111.62 34.97 127.24 35.22 199.3 98.58 41.18 187.82 81.64 37.87 204.16 89.61 34.71 203.8 125.91 32.11 210.78 131.78

1.18 0.23 0.48 1.19 1.29 0.24 0.59 1.35 1.33 0.28 0.59 1.23 1.6 0.48 0.39 1.13 0.48 0.44 22.62 32.43 2.51 8.26 4.13 0.97 8.69 4.02 1 6.18 2.92 0.8 36.2 34.9 31.4 2.09 0.68 1.98 1.92 0.47 2.06 0.35 2.69 2.29 0.51 2.59 0.54 2.4 1.77 0.46 2.39 2.65 0.55 3.57 2.27 1.81 2.72 1.63 0.72 2.7 1.44

423 428 314 429 429 431 307 428 427 430 307 425 426 435 320 427 431 317 424 418 430 427 426 428 426 432 429 431 431 433 429 432 433 422 427 429 429 429 427 429 428 427 432 426 430 430 430 431 429 428 430 441 440 435 439 439 437 438 435

449 465 344 427 456 456 343 406 454 449 310 433 363 229 301 86 223 333 174 142 209 270 309 334 261 314 344 334 383 371 270 326 241 357 363 368 367 354 298 381 300 339 339 304 340 300 316 319 289 290 307 295 274 235 305 325 275 311 357

4 3 51 2 5 2 61 2 5 3 63 3 4 22 47 2 40 69 42 56 36 12 12 12 12 12 11 9 9 9 45 47 42 5 6 3 6 5 5 4 4 7 5 6 5 4 6 4 4 9 4 5 7 12 4 4 6 4 4

31.21 8.46 0.95 63.46 27.82 11.33 0.97 67.57 28.51 10.72 0.93 46.93 39.3 2.2 0.83 57.41 1.19 0.64 53.34 58.29 7.02 69.3 34.44 8.1 69.8 32.57 9.17 66.68 33.51 8.51 80.2 73.6 75.5 40.09 10.6 67.39 31.71 9.3 45.28 9.39 72.4 32.88 10.32 41.85 10.35 66.5 31.15 12.89 65.05 28.14 12.32 69.32 32.69 14.8 66.78 38.78 11.69 67.67 36.95

RI PT

Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings

SC

Kupe South-4

4180 4180 4180 4185 4185 4185 4185 4190 4190 4190 4190 4195 3995 3995 3995 4000 4000 4000 3645 3645 3645 2466 2466 2466 2530 2530 2530 2615 2615 2615 2460 2618 2664 4083 4083 4101 4101 4101 4107 4107 4149 4149 4149 4161 4161 4173 4173 4173 4179 4179 4179 4110 4110 4110 4137 4137 4137 4158 4158

M AN U

Kopuwai-1

Shaly coal Mudstone Mudstone Coal Shaly coal Mudstone Mudstone Coal Shaly coal Mudstone Mudstone Coal Coal Mudstone Mudstone Coal Mudstone Mudstone Coal Coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Coal Coal Bulk coal Mudstone Coal Shaly coal Mudstone Bulk coal Mudstone Coal Shaly coal Mudstone Bulk coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal

TE D

Kiwi-1

0.10 0.11 0.31 0.09 0.10 0.11 0.32 0.09 0.10 0.12 0.32 0.09 0.10 0.13 0.18 0.10 0.18 0.23 0.02 0.03 0.01 0.03 0.03 0.02 0.03 0.03 0.03 0.04 0.04 0.03 0.02 0.02 0.03 0.09 0.11 0.07 0.09 0.10 0.09 0.08 0.08 0.10 0.09 0.09 0.10 0.07 0.11 0.11 0.07 0.11 0.11 0.07 0.10 0.11 0.07 0.06 0.07 0.09 0.08

155.4 44.1 4.7 299.7 140.8 58.0 4.9 301.6 144.1 54.6 4.2 223.8 158.2 5.8 3.1 54.3 3.2 2.8 95.0 85.1 14.9 193.6 109.6 27.7 188.3 105.7 32.5 232.3 133.7 32.4 222.1 245.5 187.3 158.2 43.1 265.9 128.0 36.4 148.1 39.1 235.8 124.0 38.2 140.6 38.9 214.8 110.2 46.1 201.9 91.4 42.4 219.7 99.6 38.8 220.1 134.3 34.4 232.7 143.8

ACCEPTED MANUSCRIPT

AC C Gentle Annie Popunga Mine

3.51 9.7 4.16 0.74 3.69 2.41 0.26 0.44 5.21 0.13 4.01 4.58 2.14 3.97 2.19 6.12 2.77 0.48 0.23 0.09 10.93 3.68 0.18 0.51 1.96 12.56 7.38 1.03 5.54 16.71 9.8 0.02 15.38 9.11 0.02 12.05 0.02 16.03 10.81 1.35 15.42 10.28 4.78 13.58 9.52 3.93 14.62 9.29 3.92 14.27 9.64 0.82 14.67 10.66 1.04 2.64

34.55 225.01 104.71 34.26 149.19 103.91 23.75 18.4 171.82 6.51 141.96 169.05 100.63 142.95 97.37 171.83 106.43 33.15 14.86 2.78 175.98 68.78 6.38 20.08 51.1 198.85 132.23 26.67 143.69 256.39 123.44 0.72 252.25 122.18 0.69 194.41 0.73 236.62 147.19 25.06 234.2 142.52 62.52 236.74 137.64 57.54 243.02 138.13 53.51 226.07 107.35 11.55 221.76 144.63 17.72 146.24

0.59 10.68 7.02 2.44 16.15 8.67 2.44 0.53 11.01 0.37 12.97 12.85 4.68 12.21 4.25 14.72 6.27 2.34 1.82 0.93 16.71 8.94 1.39 0.96 2.05 6.58 3.89 0.9 18.67 6.09 3.78 0.47 6.33 3.34 0.52 14.76 1.26 5.27 3.06 0.95 5.43 2.85 1.24 9.03 2.86 1.26 7.73 2.8 1.19 8.33 5.58 4.57 5.82 4.51 2.78 18.3

434 421 421 417 429 425 427 430 425 427 427 428 427 423 426 424 427 430 427 433 423 416 430 428 425 424 428 428 425 423 422 432 424 418 433 425 437 423 421 425 423 423 427 423 424 427 422 422 427 421 425 425 427 424 425 420

294 325 287 309 211 282 268 390 257 296 203 251 304 227 299 258 315 296 224 126 254 224 141 287 275 306 328 345 218 374 340 80 372 372 74 342 63 365 387 319 366 386 367 379 396 371 379 406 355 323 344 188 354 360 216 232

5 15 19 22 23 23 28 11 16 17 19 19 14 19 13 22 19 21 27 42 24 29 31 14 11 10 10 12 28 9 10 52 9 10 56 26 109 8 8 12 8 8 7 14 8 8 12 8 8 12 18 74 9 11 34 29

11.76 69.23 36.51 11.09 70.65 36.9 8.86 4.72 66.94 2.2 69.88 67.4 33.09 63.07 32.58 66.71 33.77 11.2 6.62 2.21 69.36 30.67 4.52 7 18.6 64.94 40.31 7.72 65.82 68.62 36.27 0.9 67.88 32.87 0.93 56.82 1.16 64.83 38.05 7.86 64.05 36.89 17.02 62.42 34.76 15.52 64.14 34.01 15.09 70.01 31.19 6.14 62.71 40.23 8.22 62.99

0.09 0.04 0.04 0.02 0.02 0.02 0.01 0.02 0.03 0.02 0.03 0.03 0.02 0.03 0.02 0.03 0.03 0.01 0.02 0.03 0.06 0.05 0.03 0.02 0.04 0.06 0.05 0.04 0.04 0.06 0.07 0.03 0.06 0.07 0.03 0.06 0.03 0.06 0.07 0.05 0.06 0.07 0.07 0.05 0.06 0.06 0.06 0.06 0.07 0.06 0.08 0.07 0.06 0.07 0.06 0.02

38.1 234.7 108.9 35.0 152.9 106.3 24.0 18.8 177.0 6.6 146.0 173.6 102.8 146.9 99.6 178.0 109.2 33.6 15.1 2.9 186.9 72.5 6.6 20.6 53.1 211.4 139.6 27.7 149.2 273.1 133.2 0.7 267.6 131.3 0.7 206.5 0.8 252.7 158.0 26.4 249.6 152.8 67.3 250.3 147.2 61.5 257.6 147.4 57.4 240.3 117.0 12.4 236.4 155.3 18.8 148.9

0

Outcrop

1.1

135.3

10.11

426

245

18

55.12

0.01

136.4

SC

RI PT

Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Cuttings Outcrop

M AN U

4158 3637 3637 3637 3664 3664 3664 3686.6 3687.48 3688.12 3688.73 3689.31 3689.31 3690.42 3690.42 3709 3709 3709 3763 3826 3871 3871 3871 3934 3946 3994 3994 3994 3709 3775 3775 3775 3784 3784 3784 3817 3817 3820 3820 3820 3823 3823 3823 3826 3826 3826 3832 3832 3832 3853 3853 3853 3859 3859 3859 0

EP

Wainui-1

Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Mudstone Coal Mudstone Coal Coal Shaly coal Coal Shaly coal Coal Shaly coal Mudstone Mudstone Mudstone Coal Shaly coal Mudstone Mudstone Mudstone Coal Shaly coal Mudstone Coal Coal Shaly coal Mudstone Coal Shaly coal Mudstone Bulk coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Shaly coal Mudstone Coal Coal & shaly coal

TE D

Taranga-1 Tane-1

ACCEPTED MANUSCRIPT

Table 2: GC biomarker values for Rakopi Formation samples under study for all three wells. Samples

Cape Farewell-1

CPI

OEP

TAR

Paq

ACL

2.74 2.68 3.18 9.39 6.37 8.39 8.24 3.97 6.95 9.08 9.54 6.59 5.69 8.83 8.12 5.03 8.16 7.16 8.05 7.69 10.91 5.71 3.27 8.32 4.92

0.50 0.48 0.46 1.79 1.13 2.88 3.40 0.67 4.86 2.43 4.37 1.17 7.88 8.78 7.38 3.76 3.22 2.86 1.93 2.28 3.82 3.36 1.76 1.86 1.24

0.19 0.15 0.16 0.28 0.21 0.32 0.36 0.14 0.75 0.26 0.37 0.16 1.15 0.87 0.86 0.96 0.36 0.37 0.23 0.30 0.30 0.45 0.43 0.22 0.26

1.05 1.03 1.04 1.33 1.23 1.32 1.35 1.11 1.12 1.32 1.38 1.06 1.27 1.31 1.33 1.29 1.14 1.13 1.28 1.29 1.43 1.17 1.16 1.18 1.17

1.23 1.07 1.13 1.05 1.15 1.15 1.16 1.10 1.02 1.19 1.23 1.07 1.19 1.09 1.11 1.16 1.04 1.06 1.13 1.14 1.21 1.20 1.06 1.14 1.14

0.17 0.09 0.14 0.91 0.56 1.29 1.69 0.27 0.79 1.65 2.50 0.38 2.62 4.43 3.76 2.39 1.62 1.39 1.01 1.18 2.57 1.07 0.62 0.65 0.47

0.70 0.84 0.80 0.51 0.69 0.68 0.68 0.72 0.62 0.64 0.64 0.80 0.55 0.52 0.49 0.47 0.67 0.62 0.66 0.67 0.61 0.65 0.66 0.74 0.74

27.66 26.95 26.92 27.77 27.16 27.23 27.21 27.34 27.43 27.47 27.47 26.83 27.75 27.86 28.00 28.10 27.39 27.75 27.58 27.33 27.60 27.51 27.53 27.04 27.16

MW/ HMW 2.12 2.14 1.99 0.76 0.91 0.43 0.34 1.35 0.64 0.35 0.24 0.78 0.29 0.17 0.19 0.31 0.32 0.37 0.47 0.42 0.24 0.49 0.74 0.62 0.81

LHC/ SHC 0.15 0.11 0.16 0.65 0.50 0.86 1.02 0.23 0.51 1.06 1.31 0.37 1.14 1.89 1.88 1.31 1.04 0.91 0.66 0.75 1.21 0.75 0.56 0.49 0.46

TMD

Waxiness

0.20 0.12 0.18 0.90 0.62 1.10 1.28 0.30 0.68 1.21 1.47 0.38 1.82 2.50 2.34 1.78 1.20 1.02 0.87 0.94 1.60 0.88 0.61 0.61 0.51

0.49 0.61 0.54 0.99 1.02 1.77 2.17 0.89 0.86 2.31 3.07 1.42 1.70 2.73 2.43 1.78 2.42 2.08 1.93 2.04 3.12 1.53 1.24 1.50 1.17

M AN U

SC

RI PT

Ph/C18

TE D

Tane-1

Pr/C17

AC C

Maui-4

Pr/Ph

EP

Well/Location

n-alkanes &isoprenoids Sample label A B C D E F G H I J K L M N O P Q R S T U V W X Y

ACCEPTED MANUSCRIPT

Table 3: GC-MS m/z-191 biomarker values for Rakopi Formation samples under study for all three wells.

Cape Farewell-1

C31 Homohopane/ C30 Hopane 3.39 1.74 3.94 1.74 1.42 1.11 1.42 1.43 1.32 0.89 0.84 0.43 1.12 1.05 0.71 0.57 0.77 0.37 1.36 1.25 1.00 0.57 0.56 0.55 0.52

SC

RI PT

Tripanes&Terpanes (m/z 191) Homohopane C29 Norhopane/ Gammacerane index C30 Hopane 0.44 0.00 0.19 0.47 0.00 0.21 0.47 0.00 0.27 0.54 0.00 0.18 0.56 0.00 0.15 0.54 0.00 0.14 0.55 0.00 0.17 0.63 0.00 0.21 0.62 0.01 0.21 0.77 0.00 0.16 0.79 0.00 0.16 0.60 0.01 0.14 1.38 0.03 0.36 1.17 0.01 0.20 0.91 0.02 0.23 1.01 0.03 0.30 0.85 0.01 0.19 0.66 0.02 0.43 0.67 0.01 0.19 0.69 0.04 0.23 0.86 0.01 0.17 0.80 0.02 0.21 0.82 0.02 0.23 0.74 0.01 0.17 0.68 0.02 0.20

TE D

Tane-1

EP

Maui-4

C32 Homohopane 22S/(22S+22R) 0.23 0.29 0.28 0.32 0.39 0.38 0.40 0.51 0.59 0.59 0.59 0.61 0.60 0.61 0.59 0.60 0.59 0.59 0.59 0.59 0.58 0.61 0.60 0.59 0.60

AC C

Well/Location

Sample label A B C D E F G H I J K L M N O P Q R S T U V W X Y

M AN U

Samples

ACCEPTED MANUSCRIPT

Table 4: GC-MS m/z-217 biomarker values for Rakopi Formation samples under study for all three wells.

AC C

C29 ββ/ (ββ + αα) 0.34 0.40 0.38 0.24 0.18 0.17 0.20 0.34 0.30 0.20 0.22 0.52 0.39 0.35 0.31 0.40 0.40 0.39 0.26 0.29 0.18 0.43 0.45 0.45 0.49

RI PT

C29 20S/ (20S+20R) 0.18 0.22 0.25 0.12 0.15 0.14 0.14 0.25 0.46 0.47 0.49 0.53 0.46 0.49 0.48 0.47 0.52 0.46 0.40 0.40 0.45 0.52 0.51 0.51 0.53

SC

TE D

0.20 0.27 0.25 0.10 0.07 0.06 0.05 0.13 0.13 0.08 0.10 0.00 0.20 0.11 0.14 0.27 0.10 0.18 0.14 0.13 0.09 0.16 0.36 0.12 0.29

M AN U

C27 Steranes

Steranes&Diasteranes (m/z 217) Steranes/ C28 Steranes C29 Steranes Hopanes 0.17 0.73 0.05 0.19 0.68 0.05 0.17 0.70 0.04 0.13 0.82 0.03 0.21 0.76 0.07 0.20 0.77 0.06 0.24 0.74 0.07 0.14 0.80 0.12 0.12 0.81 0.14 0.11 0.85 0.13 0.13 0.82 0.13 0.14 0.86 0.02 0.19 0.71 0.06 0.12 0.83 0.09 0.12 0.81 0.09 0.13 0.73 0.09 0.14 0.81 0.05 0.29 0.61 0.04 0.12 0.82 0.14 0.11 0.82 0.15 0.12 0.84 0.15 0.15 0.77 0.06 0.15 0.67 0.07 0.14 0.80 0.05 0.15 0.70 0.05

EP

Samples Well/ Sample Location label A B C D E F Maui-4 G H I J K L M N O Tane-1 P Q R S T U Cape V Farewell-1 W X Y

ACCEPTED MANUSCRIPT

Table 5: Input data used for basin modelling of Maui-4 well using Petromod. Base 324 422 1329 1707 1890

Thickness 324 198 907 378 183

1890

2008

118

2008 2030 2199 2789

2030 2199 2789 3839

22 169 590 1050

Age 0-2.4 2.4-5.3 5.3-14 14-16 16-21.8

RI PT

Top 0 324 422 1329 1707

21.8-30

30-33.5 33.5-50 50-65 65-81

SC

Layer Recent sediments Giant Foresets Manganui Moki Manganui Abel Head (Taimana/Otaraoa) Turi Mangahewa Farewell Pakawau Group

Base 236 2141 2209 2547 2610 2633 3194 3466 3492 4475

TE D

Top 0 236 2141 2209 2547 2610 2633 3194 3466 3492

AC C

EP

Layer Recent sediments Giant Foresets Ariki Manganui Taimana Tikorangi Turi (Upper Shale) Tane Member Turi Pakawau Group

M AN U

Table 6: Input data used for basin modelling of Tane-1 well using Petromod. Thickness 236 1905 68 338 63 23 561 272 26 983

Age 0-0.8 0.8-4.5 4.5-6 6-13 13-21.8 21.8-33.5 33.5-55 55-63 63-65 65-92

ACCEPTED MANUSCRIPT

Table 7: Ro data used in this study.

Hoki-1

M AN U

Kiwi-1

Depth (m) 0 0 230 1040 1280 1523 1841 2060 2342 1052 1205 3500 3520 3525 3540 4170 4185 4190 4195 4000 4005 3660 3051.048 2258.568 2429.256 2575.56 2511.6 2624.3 2475 2536 2621 4104 4152 4182 3640 3677 3687.59 3690.58 3726 3772 3889 3640 3689 3718 4000 4113 4140 4161 3781 3832

Kopuwai-1

TE D

Kupe South-4 Maui-4 North Tasman-1

Tane-1

AC C

EP

Takapou-1

Taranga-1

Wainui-1 Wainui-1

Ro (%) 0.49 0.59 0.5 0.59 0.64 0.62 0.72 0.77 0.94 0.66 0.71 0.37 0.37 0.38 0.39 0.53 0.55 0.51 0.51 0.65 0.64 0.58 0.67 0.57 0.55 0.61 0.58 0.54 0.67 0.68 0.64 0.68 0.71 0.76 0.45 0.62 0.58 0.62 0.56 0.51 0.52 0.47 0.65 0.55 0.6 0.8 0.8 0.76 0.48 0.48

RI PT

Location/Well name Gentle Annie Puponga Mine Cape Farewell-1 Fresne-1

SC

Formation North Cape

ACCEPTED MANUSCRIPT

Paturau River Cape Farewell-1 Maui-4

AC C

EP

TE D

M AN U

SC

Tane-1

3865 2.82 2500 3294.888 3386.328 3599.688 3691.128 3782.568 3288.8 3252 3831 4000 4006 4048 4080 4174 4228 4261 4402 4072 4174

0.57 0.61 0.8 0.66 0.63 0.65 0.67 0.71 0.71 0.75 0.95 0.6 0.58 0.5 0.63 0.74 0.74 0.7 0.77 0.66 0.78

RI PT

Rakopi

ACCEPTED MANUSCRIPT

TE D

M AN U

SC

RI PT

FIGURE CAPTIONS

AC C

EP

Figure 1: Location map of the studied area, Taranaki Basin, New Zealand (Modified after Ministry of Business, Innovation and Employment, New Zealand , 2014).

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

Figure 2: Stratigraphic succession of Taranaki Basin, New Zealand (Redrawn after Ministry of Business, Innovation and Employment, New Zealand, 2014) and the generalized lithostratigraphic column for the study area.

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 3: Lithostratigraphic successions with measured TOC data for some wells in the study area.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 4: Plot of total organic carbon (TOC, wt%) versus remaining hydrocarbon potential (S2, mg HC/g rock), showing source rock potential.

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

Figure 5: Van Krevlen diagram based on oxygen index (OI) versus hydrogen index (HI) showing oil prone generative type.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 6: Plot of Tmax versus vitrinite reflectance (Ro) showing maturity.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 7: Plot of Tmax versus production index (PI) showing the nature of the hydrocarbon.

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 8: Ph/n-C18 against Pr/n-C17 for source samples belonging to Rakopi Formation showing dominance of non-marine organic matter (after Peters et al., 1999).

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 9: Pr/Ph against C31 homohopane for source samples belonging to Rakopi Formation showing dominance of oxic depositional environment (after Peters et al., 2005).

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 10: Ternary cross-plot for C27, C28 and C29 steranes for Rakopi Formation samples showing dominance of C29 steranes (after Huang & Meinschein, 1979).

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 11: Cross-plot of C29 steranes indicating maturity levels of Rakopi Formation source samples under study (after Seifert & Moldowan, 1981).

AC C

EP

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

Figure 12: Variations in surface heat flow in Taranaki Basin (after Funnell et al., 1996).

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 13: Thermal burial history and temperature fitting in Maui-4 Well.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 14: Thermal burial history and temperature fitting in Tane-1 Well.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 15: Burial history and maturity levels in Maui-4 Well.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 16: Burial history and maturity levels in Tane-1 Well.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 17: Burial history curves with hydrocarbon generation zones for Pakawau Group in Maui4 Well.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 18: Burial history curves with hydrocarbon generation zones for Pakawau Group in Tane1 Well.

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

TE D

Figure 19: Hydrocarbon transformation ratio models for Pakawau Group source rocks in Maui-4 and Tane-1 wells.

TE D

M AN U

SC

RI PT

ACCEPTED MANUSCRIPT

AC C

EP

Figure 20: Simplified petroleum system event chart for both wells under study.

ACCEPTED MANUSCRIPT Manuscript title: Geochemical Characteristics, Depositional Environment and Hydrocarbon Generation Modelling of the Upper Cretaceous Pakawau Group in Taranaki Basin, New Zealand Manuscript ID: PETROL 10609

SC

M AN U

TE D

•

EP

•

Pakawau Group source rocks contain mostly Type II and Type-II-III kerogen The source originates between marine and terrestrtial organic matter. Pakawau Group for the most part have great potential for hydrocarbon generation. Their maturity ranges from immature to mature, based on Tmax and Vitrinite reflectance data. Burial history modelling indicates that the source rocks became mature for hydrocarbon expulsion during Upper Paleocene to Middle Eocene. To date, hydrocarbon is still being expelled from the source rock without attaining peak generation.

AC C

• • • •

RI PT

MANUSCRIPT HIGHLIGHTS