Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation, Koulele Area, Termit Basin, Niger

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1 Journal of Earth Science, Vol. 28, No. 6, p , December 2017 ISSN X Printed in China Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation, Koulele Area, Termit Basin, Niger Xuying Wang * 1, 2, Lunkun Wan 3, Zaixing Jiang 1, Ruohan Liu 1, Xiabin Wang 1, Wangxin Tang 1, Yi Gao 1, Shengqian Liu 1, Wenmao Xu 1 1. School of Energy Resources, China University of Geosciences, Beijing , China 2. School of Civil Engineering, Tangshan College, Tangshan , China 3. Research Institute of Petroleum Exploration and Development, PetroChina, Beijing , China Xuying Wang: ABSTRACT: Based on the sedimentary and tectonic background of the Termit Basin, this paper focuses on the Upper Cretaceous Yogou Formation and uses organic geochemistry, logging, oil testing and seismic data to analyze the primary control factors of the hydrocarbon accumulation and establish corresponding model in order to predict favorable exploration target zones of hydrocarbon reservoirs. This study demonstrates that the Upper Cretaceous Yogou Formation is a self-generation and self-accumulation type reservoir. The Yogou Formation hydrocarbon reservoirs in the Koulele area are controlled by four factors: (1) the source rock is controlled by a wide range of YS1-YS2 marine shale, (2) the sandstone reservoir is controlled by the YS3 underwater distributary channel and storm dunes, (3) migration of hydrocarbons is controlled by faults and the regional monocline structure, and (4) the accumulation of hydrocarbons is controlled by lateral seal. The structures in the western Koulele area are primarily reverse fault-blocks with large throws, and the structures in the east are dominantly fault-blocks with small throws (co-rotating and reverse) and a fault-nose. In the western Koulele area, where the facies are dominated by storm dunes on a larger scale, it is easier to form lithologic reservoirs of sandstone lens. In the eastern Koulele area, high-quality channel sandstone reservoirs, fault-blocks with small throws, and the monocline structure benefit for the formation of updip pinch out lithologic traps, fault lithologic reservoirs and fault-nose structural reservoirs. Future exploration targets should be focused in the western storm dunes zone and eastern distributary channel sand zone with small fault-blocks. KEY WORDS: hydrocarbon reservoirs, controlling factors, accumulation model, Koulele area, Yogou Formation. 0 INTRODUCTION Many oil fields have been found in the Paleogene hydrocarbon reservoirs of the Termit Basin. The main oil-bearing strata is the Paleogene Sokor Formation. Previous studies on the Termit Basin have been focused on the potential petroleum source rocks (Liu et al., 2015; Wan et al., 2014; Harouna and Philp, 2012), tectonic evolution (Liu et al., 2015, 2012a, b; Lü et al., 2015; Xue et al., 2012). However, researches on accumulation in Paleogene hydrocarbon reservoirs (Lü et al., 2012), sedimentary systems (Tang et al., 2015; Fu et al., 2012; Liu et al., 2012a), and the controlling factors of the Upper Cretaceous hydrocarbon are limited, especially regarding hydrocarbon *Corresponding author: wxy87121@126.com China University of Geosciences and Springer-Verlag GmbH Germany 2017 Manuscript received May 13, Manuscript accepted January 18, accumulation. There are several hydrocarbon reservoirs in the Upper Cretaceous Yogou Formation. The Yogou Formation in the Termit Basin has widely distributed marine source rocks and sandstone reservoirs, which are in contact with the oil source. However, the hydrocarbon reservoirs of the Yogou Formation, which lack of regional caps and are complicated by faults, are scale limited and hard to be found. Thus, understanding the controlling factors and accumulation model of the hydrocarbon reservoirs is the key to a breakthrough in the exploration potential of the Upper Cretaceous Yogou Formation. The Koulele area, spanning an area of km 2, is an important part of the exploration blocks of the Upper Cretaceous Yogou Formation. The area is covered by threedimensional seismic data and seven exploration wells without coring. The Koulele area is located in the northern Fana lowuplift of the Termit Basin and is bordered by the Araga graben to the north, the Trakes slope to the east, and the Dinga sag to the west (Fig. 1). The Koulele area is controlled by NNW-SSE en echelon tensile faults, which are consistent with the Wang, X. Y., Wan, L. K., Jiang, Z. X., et al., Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation, Koulele Area, Termit Basin, Niger. Journal of Earth Science, 28(6):

2 Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation 1127 extension direction of the area (Fig. 1). The Yogou Formation of the Koulele area is approximately m thick and is a set of anti-cyclic sedimentation with lower fine and upper coarse units (Fig. 2b). The Yogou Formation was deposited in a marine-deltaic environment and can be further subdivided into three sequences, from bottom to top, the YS1, YS2, and YS3 (Fig. 2b). Cutting logging and oil tests record hydrocarbon, and the test results show that daily oil production could reach barrels. The area has good exploration potential. Based on the sedimentary and tectonic background of the Termit Basin, this paper focuses on the Upper Cretaceous Yogou Formation and uses organic geochemistry, logging, oil testing and seismic data to analyze the primary controls and develop a model of the hydrocarbon accumulation to predict favorable exploration target zones of hydrocarbon reservoirs. The research will not only provide a geological basis for further exploration of the Koulele area but will also provide a reference for Yogou Formation hydrocarbon reservoir exploration of other blocks in the basin. 1 GEOLOGICAL SETTING 1.1 Tectonic and Sedimentary Evolution of Termit Basin Termit Basin is a Mesozoic Cenozoic rift basin above the Precambrian Jurassic basement and is in the northern part of the West and Central African rift system (WCARS) (Binks and Fairhead, 1992; Fairhead, 1986; Browne and Fairhead, 1983). The basin is elongated in a NW-SE direction and covers an area of approximately km 2 (Fig. 1). The Termit Basin experienced two rift cycles: The Paleogene rift cycle and the Cretaceous Quaternary rift cycle (Liu et al., 2012a; Lü et al., 2012; Genik, 1993) (Fig. 2a). The first cycle formed when Gondwana was breaking up and the South Atlantic was rifting which consists of two phases: an Early Cretaceous syn-rift phase and a Late Cretaceous postrift phase. In the Early Aptian to Late Albian, NE-SW stretching of the inner Africa-Arab Plate (Guiraud and Maurin, 1992) formed a series of grabens and half-grabens in the basin, controlled by NW-SE trending boundary faults that are consistent with the trend of the basement. Along the boundary faults, several kilometers of continental clastic rocks were deposited. During the Late Cretaceous, when tectonic activity was weak in the African-Arabian area and global sea level was at its highest point during the Phanerozoic, the basin experienced a massive transgression (Liu et al., 2011). In this period, the basin was filled with thick marine clastic rocks: The Donga and Yogou formations. During the Late Campanian, seawater returned to the Niger Basin. During the Maastrichtian, the western part of the basin was uplifted (Fairhead et al., 2013) and the basin was filled by thick massive braided fluvial sandstones and mudstones, called the Madama Formation. The second rift cycle occurred during the collision of the African-Arabian Plate and the Eurasian Plate and had two phases: A Paleogene syn-rift phase and a Neogene Quaternary post-rift phase. In the Late Eocene to Oligocene, the African- Arabian and Eurasian plates collided (Guiraud et al., 2005). During this time, the basin experienced strong NEE-SWW directed extension. Near the border basin, the boundary faults exhibited characteristics of inheritance. At the same time, many new faults were derived from these activities. The trend of these new faults is parallel to the trend of the boundary faults, but their tendency is opposite, forming a Y-shape in cross section. In the inner areas of the basin, where Early Cretaceous faults do not exist, a series of NNW-SSE-trending faults formed. The trend of these new faults is perpendicular to the stretching direction of the Termit Basin. During this time, sedimentation was obviously controlled by activity along the faults, and the delta-lacustrine sediments of the Sokor1 and Sokor2 formations were deposited. The post-rift corresponds to the Neogene through Quaternary. During the Early Miocene, regional uplift occurred in East Niger (Guiraud et al., 2005), and Paleogene strata experienced a certain degree of erosion. During the Miocene to Quaternary, tectonic activity was generally weak. The basin has experienced post-rift thermal subsidence, allowing for the deposition of mainly fluvial-alluvial plain deposits. 1.2 Fault System of Termit Basin There are two sets of fault systems, based on the strike of the faults: NW-SE-trending faults and NNW-SSE-trending faults (Fig. 1). Based on time and class, these faults can also be divided into two types: (1) Early Cretaceous faults that reactivated in the Paleogene, and (2) new faults formed in the Paleogene (Fig. 1). The former exists along the boundaries of the basin. These Early Cretaceous boundary faults strike NW- SE and are steep with large fault throws and scales. Most of the Early Cretaceous boundary faults cut through the sedimentary strata below Neogene Quaternary and involve the basement rocks. The latter exists both along the boundaries of the basin and within the basin. Most of these new Paleogene faults cut through Paleogene Sokor1 Formation and Sokor2 Formation, the Upper Cretaceous Madama Formation and Yogou Formation into the Donga Formation. Figure 1. Structural units and the spatial distribution of faults in the Termit Basin, located in southeastern Niger. The location of the Koulele area is marked as a red polygon.

3 1128 Xuying Wang, Lunkun Wan, Zaixing Jiang, Ruohan Liu, Xiabin Wang, Wangxin Tang, Yi Gao, and et al. On the basin boundaries, the trend of these Paleogene faults is parallel to NW-SE Early Cretaceous boundary faults, but the tendency is opposite, forming a Y-shape with the boundary faults in cross section. Within the basin, where Early Cretaceous boundary faults do not exist, there are a series of new NNW-SSE Paleogene faults. The Koulele area is dominated by the new NNW-SSE-trending Paleogene faults and all normal faults. 2 MATERIAlS AND METHODS The analysis data is insufficient in the Termit Basin. So, we used the organic geochemical data of previous studies (Liu et al., 2015) from the basin to analyze the source rocks. A total of 165 core samples cutting from the Yogou Formation were obtained from eight wells in the Termit Basin: Bgm N-1, Dbl-1, Dgl NW-1, Fana-1, Hlt-1, Mng-1, Ons-1, Yg N-1 (Fig. 1). The organic geochemical analyses were performed at the State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum. The total organic carbon (TOC) determination and Rock-Eval pyrolysis were conducted on 126 samples (100 mg). The TOC determination was conducted using a LECO CS-230 carbon analyzer. Rock-Eval pyrolysis was conducted using an OGE-II rock pyrolyzer to determine parameter S2. Kerogen was prepared from the powdered rock samples using hydrochloric and hydrofluoric acids. The soluble organic components were removed by kerogen extraction with chloroform. Finally, the elemental contents (C, H and O) of kerogen on 19 selected samples from Well Dbl-1 and Well Hlt-1 were measured. The Koulele area is covered by three-dimensional seismic and has seven exploration wells but no coring. The threedimensional seismic covers the entire Koulele area, with a total area of km 2, and a 12.5 m track pitch, 2 ms vertical sampling rate, 25 Hz dominant frequency of the Yogou Formation, and an 8 50 Hz effective bandwidth. The average velocity of the Yogou Formation is m/s. The vertical resolution is approximately 40 m. The faults have a negative impact on the quality of the seismic data, resulting in poor data quality. A total of 16 seismic amplitude stratal slices (Zeng et al., 2012, 1998a, b) were made, taking the top and bottom of the YS3 as the boundary, choosing root-mean-square (RMS) amplitude attribute, using the method of equal ratio interpolation and a 5 ms extraction time window. From these slices, six typical slices with clear outlines were selected for further analysis and interpretation. Figure 2. Stratigraphic column of the Termit Basin (a) and stratigraphy of the Yogou Formation in the Koulele area (b) (modified after Genik, 1993).

4 Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation RESULTS AND DISCUSSION 3.1 Types and Distribution of Hydrocarbon Reservoirs Koulele area has a monocline structure and is low in the west and high in the east. The area is complicated by faults and dominated by fault-block and fault-nose structures. The exploration results show that hydrocarbon reservoirs are layered in cross section and are mainly distributed in the Sequence YS3. Cutting logging and oil tests record hydrocarbon, and the test results show that daily oil production could reach barrels. The area has good exploration potential. By the control of the complicated structure and varied sedimentary facies, the types of hydrocarbon reservoirs are rich in the Koulele area. There are fault-nose structural traps and reservoirs, fault lithologic reservoirs, and two types of lithologic reservoirs including updip pinch out lithologic reservoirs and lithologic reservoirs of sandstone lens. The area is dominated by fault lithologic reservoirs and updip pinch out lithologic reservoirs. A total of seven exploration wells were drilled in the Koulele area. The drilling of Well KCS-1 experienced the fault, resulting in no hydrocarbon record. The other six exploration wells obtained commercial hydrocarbon flow. Hydrocarbon reservoirs are mainly distributed in three well areas: Fana-1 well area, KCN-2 well area and KDeep-1 well area. Fana-1 well area is dominated by fault-block with large throw in the northwestern part of the Koulele area. And the base of YS3 is dominated by storm dunes that are spatially extensive, so it is very easy to form lithologic reservoirs of sandstone lens (Fig. 3a). KCN-2 well area is in the fault-nose structure and has a somewhat high position that is favorable for fault-nose structural trap reservoirs (Fig. 3b). KDeep-1 well area is in the eastern fault terrace. Here, distributary channel sandstones, the good lateral blocking terrace, and the monocline structure enable the formation of updip pinch out lithologic trap reservoirs and fault lithologic reservoirs. In some cases with smallscale channels, channel sandstone lens could form lithologic traps and reservoirs. (Fig. 3c). 3.2 Controlling Factors of Hydrocarbon Reservoirs Based on the analysis of organic geochemistry, logging, and seismic data, the Yogou Formation hydrocarbon reservoirs in the Koulele area are controlled by four factors: (1) the source rock is controlled by a wide range of the YS1-YS2 marine shale; (2) the sandstone reservoir is controlled by the YS3 underwater distributary channels and storm dunes; (3) the hydrocarbon migration is controlled by faults and monocline structure; and (4) the hydrocarbon accumulation is controlled by lateral seal Source rock controlled by a wide range of YS1-YS2 marine shale The Termit Basin has three sets of source rocks (Liu et al., 2015; Wan et al., 2014; Harouna and Philp, 2012): Lower Cretaceous lacustrine shale, Upper Cretaceous marine shale, and Paleogene lacustrine shale. Oil-source correlation studies conclude that the crude oil source of the Termit Basin is primarily from Upper Cretaceous Yogou Formation marine shale (Lü et al., 2015), mainly in YS1-YS2. The gray to dark lacustrine shale of YS1-YS2 is m thick and widely distributed. The TOC varies from 0.60% to 23.32%, with an average of 2.60%. S2 varies from 0.40 to mg HC/g rock, with an average of 5.59 mg HC/g rock, indicating fair to excellent hydrocarbon generation potential (Peters and Cassa, 1994). Based on a graph of H/C versus O/C (Table 1) (Fig. 4), the source rock is dominated by Type II-III kerogen. The burial and maturity evolution suggest that the rocks are currently in the middle maturity stage (Wan et al., 2014) (Fig. 5), within the peak window of oil generation. Figure 3. The oil reservoir profiles of the YS3 sequence in the Koulele area (profiles a-a, b-b, c-c as shown in Fig. 7a). Figure 4. The graph of H/C versus O/C showing the type of kerogens from the Yogou Formation.

5 1130 Xuying Wang, Lunkun Wan, Zaixing Jiang, Ruohan Liu, Xiabin Wang, Wangxin Tang, Yi Gao, and et al. Figure 5. Burial and maturity evolution of Well DD-1 (location in Fig. 1) (modified after Wan et al., 2014). Table 1 The H/C and O/C values of kerogens from the Yogou Formation Well Sample Depth (m) H/C O/C Dbl-1 DB Dbl-1 DB Dbl-1 DB Dbl-1 DB Dbl-1 DB Dbl-1 DB Dbl-1 DB Dbl-1 DB Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT Hlt-1 HT are the favorable sandstone reservoirs of the Yogou Formation. The bottom of YS3 has the deepest water level and belongs to an open shelf environment. It is dominated by a neritic shelf controlled by storms, including storm dunes and shelf mud. Storm dunes here are formed from storm waves carrying delta front clastics (Jiang, 2010; Jiang et al., 1990). Banded storm dunes, extending parallel to the shoreline, are distributed in the shelf mud. Their lithology is mainly fine sandstone (Fig. 6). The thickness of a single storm dune is 2 8 m. The curve shapes are mainly of a box-type or bell-type (Fig. 6). In the stratal slices, they are characterized by banding amplitude anomalies that are parallel to the coastline (Figs. 7a, 7b). During regression stage, delta front begins to develop and makes up the major sedimentary facies, dominated by banding underwater distributary channels. The lithology of the underwater distributary channels is mainly medium-fine sandstone (Fig. 6). The thickness of single channel is 2 9 m. The thickness of vertical stacking is up to 100 m. The curve shapes are mainly box-type or bell-type (Fig. 6). In the stratal slices, the channels are characterized by high RMS amplitudes, vermicular reflection, and banding distributions (Figs. 7b 7f). According to the position and hydrodynamic conditions, the delta front is divided into inner front and outer front. In the inner front, the river function is obvious, and it is dominated by distributary channels. In the outer front, the lake function plays a major role, and it is away from the lake shoreline. It is dominated by sheet sands in the outer front. Ongoing marine regression caused the water to become shallow, and deltaic progradation occurred. Finally, it is dominated by reticulated inner-front channels in the upper sections of YS3. Data from Liu et al. (2015). Viewed from above, YS1-YS2 lacustrine shale is widely distributed, fair-excellent source rock, and has a great hydrocarbon potential. Furthermore, it is currently in the stage of middle maturity, simultaneously at the peak of oil generation. Yogou Formation YS1 sandstone reservoir has the advantage of proximity and easier access. The reservoir-forming combination of the Yogou Formation can be classified as self-generation and selfaccumulation Sandstone reservoirs controlled by YS3 underwater distributary channels and storm dunes Well logs reveal that the Yogou Formation of the Koulele area has anticyclic sedimentation with lower fine and upper coarse sediments (Fig. 2b) and can be further subdivided into three sequences, from bottom to top: YS1, YS2, and YS3 (Fig. 2b). The source provenance area is in the northeastern part of the basin. The neritic shelf phase is dominant in the sequence YS1-YS2, and a thick marine shale was deposited. The delta front and neritic shelf are dominant in the sequence YS3 and Figure 6. Lithology, curve features, and microfacies interpretation of Well KDeep-1 in the Koulele area (location in Fig. 7). Locations of the typical stratal slices are also marked.

6 Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation 1131 Figure 7. Typical stratal slices of the YS3 sequence in the Koulele area (locations of the slices in Fig. 6). The YS3 sequence has a good quality reservoir with medium porosity and medium permeability. Well logging interpretation shows that the porosity varies from 15% to 25%, and the permeability varies from 5 to 200 md. Different sedimentary microfacies have different reservoir properties. For example, the distributary channel (average porosity 20%, average permeability 76 md), storm dunes (18%, 66 md), and mouth bars (20%, 73 md) have better porosities. Sheet sand (12%, 16 md) has poorer properties. In terms of scale, multi-stage superimposed distributary channels have the largest scale. With lateral migration and vertical accretion, distributary channels can be sizable, high-quality sandstone reservoirs. Furthermore, storm dunes at the bottom of YS3 also have large spatial scales and are high-quality reservoirs, whereas the mouth bar has a localized small spatial extent. Sheet sand has poor properties and is thin. Both the mouth bar and sheet sand do not have the properties to be classified as a high-quality reservoir Migration controlled by faults and monocline structure The Koulele area is dominated by the new NNW-SSEtrending Paleogene normal faults. Most of these new Paleogene faults cut through Paleogene Sokor1 Formation and Sokor2 Formation, the Upper Cretaceous Madama Formation and Yogou Formation into the Donga Formation. From the hydrocarbon reservoirs found in the Sokor and Yogou Formation, the reservoirs are mainly distributed along these normal faults. These faults could be good migration pathways. Fault throw obviously has a control on both the vertical and lateral migration. If the throw is large, it is dominated by vertical migration along the faults and supplemented by lateral migration. If the throw is small, lateral migration along YS3 sandstone is likely dominant. Furthermore, Koulele area has a monocline structure and is low in the west and high in the east. The monocline structure controls the trend of hydrocarbon migration. Hydrocarbon always migrates continuously from high positions of structures to low positions. Hydrocarbon generated from YS1-YS2 marine source rocks migrates into YS3 through pathways along faults and then migrates into the high positions of structures by buoyancy-driven mechanisms Accumulation controlled by lateral seal Koulele area is dominated by fault-block and fault-nose structures (Fig. 8). YS3 sandstone reservoir lacks a thick regional

7 1132 Xuying Wang, Lunkun Wan, Zaixing Jiang, Ruohan Liu, Xiabin Wang, Wangxin Tang, Yi Gao, and et al. cap. The overlying Madama Formation sandstone is a very good carrier bed. Hydrocarbons can easily migrate upward vertically through faults and laterally within the Madama sandstone. The lateral seal is the key to controlling hydrocarbon accumulation. The fault-nose structure has a high position that is the most favorable for hydrocarbon accumulation (Fig. 8a). With the lateral seal, it can form a hydrocarbon reservoir that may be filled. On the fault-block structure, whether the lateral seal will work depends on whether the faults and sandstones align. The fault-block can be divided into a reverse fault-block (the fault and strata have the opposite tendency) (Figs. 8b, 8c) and a corotating fault-block (the fault and strata have the same tendency) (Figs. 8d, 8e). If the fault throw of the reverse fault-block is larger than the thickness of YS3, the YS3 sandstone reservoir is juxtaposed against the Madama sandstone, and there would be no lateral seal to stop hydrocarbon migration (Fig. 8b). If the throw of the reverse fault-block is small, the sandstone and mudstone interbeds of YS3 would be on both sides of faults across from each other, and there is a lateral seal to trap hydrocarbons (Fig. 8c). If the fault throw of the co-rotating faultblock is larger than the thickness of YS3, the YS3 sandstone reservoir is juxtaposed against YS1-YS2 marine shale, and there is a good chance of a lateral seal to gather hydrocarbon effectively (Fig. 8d). If the throw of the co-rotating fault-block is small, the sandstone and mudstone interbeds of YS3 would be on both sides of faults across from each other, and there is a lateral seal to trap hydrocarbons (Fig. 8e). Figure 8. The capacity of lateral seal and hydrocarbon accumulation in different structural styles. In general, the different structural styles have different fault seal possibilities controlling the accumulation of hydrocarbons. The fault-nose and co-rotating fault-block with a large throw have the highest probability of trapping hydrocarbon, followed by a fault-block with a small throw of both corotating and reverse. A reverse fault-block with a large throw has the lowest fault seal probability and would likely not be able to trap oil and gas. 3.3 Accumulation Model of Hydrocarbon Reservoirs An analysis of the factors controlling the accumulation of hydrocarbons suggests that lateral the seal plays a major role. Based on the analysis of the hydrocarbon reservoirs and analyzing their favorable sand reservoirs and structural positions, we summarize the model of hydrocarbon accumulation in the Yogou Formation in the Koulele area. Because different locations of the study area have different structural characteristics, there are different sandstone reservoir characteristics and hence different models of hydrocarbon accumulation. In the two east-west profiles (Fig. 9), the western Koulele area is dominated by reverse fault-blocks with large throws, and the east is dominated by fault-blocks with small throws (co-rotating and reverse) and fault-nose structures. In the western Koulele area (Fig. 9), which is far away from the source, distributary channels are rare and the structures are dominantly reverse fault-blocks with large throws. Here, the YS3 sandstone reservoir is juxtaposed against the Madama sandstone, and there are no lateral seal to trap hydrocarbons. However, the base of YS3 is dominated by storm dunes that are spatially extensive, so it is very easy to form lithologic reservoirs of sandstone lens. In the eastern Koulele area (Fig. 9), which is close to the source, there are distributary channels and fault-blocks with small throws. Here, high-quality sandstone reservoirs, good lateral blocking structures, and the monocline structure enable the formation of updip pinch out lithologic trap reservoirs and fault lithologic reservoirs. Moreover, the fault-nose structure around Well KCN-2 has a somewhat high position that is favorable for hydrocarbon accumulation, fault-nose structural trap reservoirs form easily. In some cases with small-scale channels, channel sandstone lens may form lithologic traps and reservoirs. Figure 9. Accumulation model of hydrocarbon reservoirs of Yogou Formation in Koulele area (profiles A-A, B-B as shown in Fig. 7a).

8 Controlling Factors and Accumulation Model of Hydrocarbon Reservoirs in the Upper Cretaceous Yogou Formation Future Directions in Exploration Oil and gas resources are rich in the Koulele area. Based on our analysis of the controlling factors and accumulation model, we optimized favorable exploration target zones of hydrocarbon reservoirs. The optimum principle of hydrocarbon reservoirs includes two key aspects on the sediments and structure. The sediments should be in a zone that is dominated by distributary channels and storm dunes, and the structures should be faultblocks with small throws and fault-noses. Combined with the sand distribution and its structural position, there are three favorable zones. First, in the western Koulele area that is dominated by spatially extensive storm dunes, lithologic reservoirs of sandstone lens are easily formed. Second, the fault-nose zone around Well KCN-2 is the most favorable for fault-nose structural traps and reservoirs. Third, in the eastern Koulele area, high-quality channel sandstone reservoirs, small throw fault-blocks, and the monocline structure enable the formation of updip pinch out lithologic reservoirs and fault lithologic reservoirs. As exploration has been begun around the fault-nose zone around Well KCN-2, future exploration targets should be focused in the eastern distributary channel sand zone with small fault-blocks and in the western storm dunes zone. 4 CONCLUSION The Upper Cretaceous Yogou Formation has a selfgeneration and self-accumulation type reservoir. The Yogou Formation reservoirs in the Koulele area are controlled by four factors: (1) the source rocks are controlled by a wide range of YS1-YS2 marine shale; (2) the sandstone reservoir is controlled by the YS3 underwater distributary channel and storm dunes; (3) hydrocarbon migration is controlled by faults and the regional monocline structure; and (4) accumulation is controlled by lateral seal. Different structural styles lead to different lateral seal abilities and hence different hydrocarbon accumulations. Structures that are fault-nose and co-rotating fault-blocks with large throws have the best probability to trap hydrocarbon accumulation, followed by co-rotating and reverse fault-blocks with small throws. Reverse fault-blocks with large throws are the least favorable structure and are unable to trap oil and gas. The structures of the western Koulele area are dominated by reverse fault-blocks with large throws, and the structures in the east are dominated by fault-blocks with small throws (corotating and reverse) and fault-noses. In the western Koulele area, spatially extensive storm dunes enable the formation of lithologic reservoirs of sandstone lens. In the eastern Koulele area, high-quality channel sandstone reservoirs, small throw fault-blocks, and the monocline structure allow for the formation of updip pinch out lithologic traps and fault lithologic reservoirs. In addition, the fault-nose zone around Well KCN-2 likely has a fault-nose structural trap and reservoir. The area around the fault-nose zone is now undergoing exploration, so future exploration targets should focus on the western storm dune zones and the eastern distributary channel sand zone with small fault-blocks. ACKNOWLEDGMENTS This study was supported by the National Science and Technology Major Project of China (No. 2011ZX ). We sincerely thank the African Institute of CNODC for providing research data, close cooperation and comments, especially on the regional tectonics. We are also grateful for the two anonymous reviewers and the editors of Journal of Earth Science. The final publication is available at Springer via REFERENCES CITED Binks, R. M., Fairhead, J. D., A Plate Tectonic Setting for Mesozoic Rifts of West and Central Africa. Tectonophysics, 213(1/2): Browne, S. E., Fairhead, J. 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