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Method for identifying effective carbonate source rocks: a case study from Middle–Upper Ordovician in Tarim Basin, China

Method for identifying effective carbonate source rocks: a case study from Middle–Upper... Hydrocarbon expulsion occurs only when pore fluid pressure due to hydrocarbon generation in source rock exceeds the force against migration in the adjacent carrier beds. Taking the Middle–Upper Ordovician carbonate source rock of Tarim Basin in China as an example, this paper proposes a method that identifies effective carbonate source rock based on the principles of mass balance. Data from the Well YW2 indicate that the Middle Ordovician Yijianfang Formation contains effective carbonate source rocks with low present-day TOC. Geological and geochemical analysis suggests that the hydrocarbons in the carbonate interval are likely self-generated and retained. Regular steranes from GC–MS analysis of oil extracts in this interval display similar features to those of the crude oil samples in Tabei area, indicating that the crude oil probably was migrated from the effective source rocks. By applying to other wells in the basin, the identified effective carbonate source rocks and non-source rock carbonates can be effectively identified and consistent with the actual exploration results, validating the method. Considering the contribution from the identified effective source rocks with low present-day TOC (TOC ) is considered, the long-standing puzzle between the proved 3P oil reserves and estimated resources in the basin pd can be reasonably explained. Keywords Effective carbonate source rock · Mass balance approach · Low present-day TOC · Ordovician · Tarim Basin 1 Introduction Edited by Jie Hao In the past, scholars in the world have put forward different definitions of effective carbonate source rock. For exam- * Jun-Qing Chen ple, Hunt (1995) regarded rocks that have generated and cjq7745@163.com expelled hydrocarbon fluid as effective source rocks. Pang * Xiong-Qi Pang et al. (1993) considered only those rocks that expel free- pangxqcup@163.com phase hydrocarbons in large quantities are effective source rocks. To be specific, only those rocks that contain sufficient State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, organic matter (quantity) with good kerogen type (quality) Beijing 102249, China at a certain thermal evolution stage (maturity) and that are Beijing Key Laboratory of Optical Detection Technology capable of expelling sufficient hydrocarbons for forming for Oil and Gas, China University of Petroleum, commercial accumulations, are referred as effective source Beijing 102249, China rocks. Depending on quality and maturity, the threshold of College of Geoscience, China University of Petroleum, TOC value as an effective source rock varies. In the past, Beijing 102249, China people proposed different threshold TOC values in carbon- Geological Survey of Canada, Calgary, AB T2L 2A7, ate rock, from 0.1% to 0.5%, based on different methods in Canada various basins (Table 1). For the convenience of discussion, Research Institute of Petroleum Exploration we take 0.5% as the threshold value of present-day TOC and Development, PetroChina Huabei Oilfield Company, (TOC ) to define the high organic matter and low organic pd Renqiu 062550, Hebei, China matter carbonate source rocks. For mature source rock, the China University of Geosciences, Beijing 100083, China Vol.:(0123456789) 1 3 1492 Petroleum Science (2020) 17:1491–1511 Table 1 Various threshold of TOC value as an effective carbonate source rock from different authors References Threshold of TOC value as an effective carbonate source rock Chen (1985) and Qin et al. (2004) 0.1 Ronov (1958), Liu and Shi (1994) and Huo et al. (2019) 0.2 Hunt (1967) and Tissot and Welte (1978) 0.3 Palacas (1984) and Peng et al. (2008) 0.4 Qiu et al. (1998) and Zhang et al. (2002a, 2012) 0.5 TOC denotes the residue of organic matters in the source in China as a case study to illustrate the procedure and dem- pd rocks after generation and expulsion, which does not rep- onstrate the feasibility of the proposed method. resent the initial amount TOC prior to thermal decompo- sition. Jarvie (2014) shows that depending on the type of kerogen, up to 80% of original TOC (TOC ) can be con- 2 Geological background, data verted to hydrocarbons. For example, Type I kerogen has initial hydrogen index HI > 700 mg/g (Jones 1984), which and methodology means that at least 58% TOC can be converted to hydro- carbons. Pang et al. (2014) attempted to restore the initial 2.1 Geological background TOC value by introducing a recovery factor in a study of carbonate source rocks. Based on data from six petroliferous The Tarim Basin, the largest subaerial petroliferous basin in China, has been estimated of about 20 × 10 tons oil equiva- sedimentary basins in China, the recovery coefficient (TOC / TOC ) for Type I, Type II and Type III kerogen can reach lent of hydrocarbon resources (Wang et al. 2015). In recent pd years, more discoveries have been made from the Ordovician 3.2, 2.2 and 1.5, respectively. Utilizing present-day TOC threshold as a measure for carbonate successions in Yingmaili, Halahatang, Hudson, Xinken areas in Tabei Uplift and Tazhong Uplift (Fig. 1a), determining effective source rock is rather arbitrary, incon- sistent and incomparable across source rock units, even for with the 3P reserves of 1.04 × 10 tons in Tazhong Uplift and 3.0 × 10 tons in Tabei Uplift, respectively. In contrast, an the same source rock with different thermal maturities. For example, Ronov (1958) suggested a TOC threshold of 1.4% early resource appraisal based on source rock capacity indi- cated 3.794 × 10 tons oil equivalent hydrocarbon resources for shales in the Upper Devonian Formation in the Sibe- rian platform. Organic geochemical and discoveries data only (Yang 2012), smaller than what have been already dis- covered, a long-standing puzzle in the Tarim hydrocarbon indicated that the effective source rock of Paleogene Shahe- jie Formation in Jiyang Depression, Bohaibay Basin has a exploration. Although geochemical studies suggest that hydrocarbons accumulated in the Ordovician succession are threshold of above 2% (Wang et al. 2013). Due to the fact that the adsorption and retention capacities of carbonates of geochemical signatures similar to typical hydrocarbons originated from the source rocks in Middle–Upper Ordovi- are weaker than those of clays, Tissot and Welte (1984) took 0.3% as a threshold TOC value in carbonate source rocks cian (Fig. 1b) (Zhang et al. 2000, 2002b, 2004; Wang and Xiao 2004; Zhang et al. 2007; Zhao et al. 2008; Li et al. based on empirical observations. In defining an effective source rock, the quantity, quality 2008; Wang et al. 2014), more than 200 prospecting wells penetrated the Middle–Upper Ordovician succession show and thermal maturity of kerogen are the three primary ele- ments, in addition to the characteristics of conduits imme- limited high T OC source rock beds across the basin pd (Fig. 1c). The carbon deficit in mass balance implies addi- diately in contacts with the source rock. However, the three elements compensate for each other, making a TOC thresh- tional sources, perhaps from the low-TOC source rock beds pd contributing to the discovered reserves (Huo et al. 2013; old as the sole criterion inconsistent. For example, kero- gens with better quality or higher thermal maturity could Pang et al. 2014; Liu et al. 2017). From bottom to top, the Ordovician stratigraphic lower down the threshold of initial TOC for an effective source rock because of more organic matter for conversion sequences in the Tarim Basin are the Lower Ordovician Yingshan Formation (O y), the Middle Ordovician Yiji- or lighter hydrocarbon fluid products. In this paper, we propose a method for identifying anfang Formation (O y), the Tumuxiuke Formation (O t), 2 3 the Lianglitage Formation (O l) and the Upper Ordovician effective source rock in carbonates using mass balance approaches by quantifying hydrocarbon expulsion and use Sangtamu Formation (O t) (Fig.  1b). Among the forma- tions, the Sangtamu Formation is dominated by clastic rocks, the Middle–Upper Ordovician source rock of Tarim Basin 1 3 Petroleum Science (2020) 17:1491–1511 1493 Fig. 1 The distribution of discovered hydrocarbon and Ordovician source rocks, Tarim Basin. a The distribution of discovered hydrocarbons, Tarim Basin; b strati- graphic framework of the Ordovician System in the Platform of the Tarim Basin; c The present-day measured TOC values of the Upper–Middle Ordovician source rocks (the locations of sample wells are shown in a) 1 3 Qimugen uplift Tazhong uplift Tadong uplift 400000 1200000 (b) LLS 0 200 km (a) 1 100000 Pay uplift GR Korla Lithology Example Tarim basin zone LN63 LD2 H7-2 LLD Luntai LN46 KN1 LD1 XK4 0 150 1 100000 H9001 LG39 HD23 Q2 Kongquehe slope YM2 YW2 HD17 HD13 Manjiaer depression LX1 Awati depression TD1 ZG17-1 TD2 Kashi ZG101 TZ10 Kashi depression Bachu uplift TZ45 TZ201 ZG9 TAC1 Ruoqiang M5-1 TZ79 GC4 M402 H3 TG1 HT1 Maigaiti slope Tangguzibasi depression TN1 Minbei uplift Yecheng depression Minfeng 400000 1200000 H6 Well of Typical well Well of Sample Place Boundary of Boundary of Oil Gas st nd Ordovician for method oil-source well name 1 order 2 order reservoirs reservoirs source rock verification correlation structural unit structural unit 1.0 (c) N =23 0.8 Data from experiment Data collected from oilfield 0.6 TOC= 0.5% ZG8 0.4 0.2 Limestone Mudstone Marlstone Bioclastic Micrite Sandy limestone limestone mudstone Yingjisu depression uplift Tabei Kuqa depression Ruobuzhuang uplift Minfeng depression Ruoqiang depression HD23 HD13 HD17 LN46 Q2 LD1 LD2 LG39 LN63 ZG101 ZG17-1 ZG9 TZ201 TZ79 M402 M5-1 H3 HT1 TG1 TN1 GC4 LX1 YW2 4200000 4600000 TOC,% Lower Ordovician Middle Ordovician Upper Ordovician Epoch Sang- Yingshan Yijianfang Tumuxiuke Lianglitage Formation tamu Thickness, 0~703 0~157 0~106 0~800 0~1067 m 1494 Petroleum Science (2020) 17:1491–1511 while the other formations are mainly composed of carbon- per minute until temperature reaching 650 °C. Finally, the ate rocks. temperature decreases naturally. The Yangwu 2 (YW2) well, located to the west of The GC–MS analysis results for the interval from the Yangwu 2 (YW2) structure in the Manbei structural zone YW2 well (4 samples) and those of discovered oils in the in the north of Manjiaer depression, Tarim Basin (Fig. 1a), Yingmaili (3 samples) and Halahatang oilfields (3 sam- has been studied to investigate the generation potential of ples) in the Tabei area are collected from the Tarim Oilfield the Middle–Upper Ordovician source rocks in recent years Company, PetroChina. The sample locations are shown in (Zhu et al. 2011). This well is also chosen as a case in this Fig. 1a. Other data, including reservoir volumetric param- study because of two reasons, (a) continuous sampling of eters, oil density, water salinity, formation pressure and every meter for entire interval of interested; and (b) deep- temperature and others, are also collected from the com- est penetration reaching the Middle Ordovician carbonate. pany in the study. Eighty six samples were taken from the entire Ordovician interval penetrated from 6411 m to 6496 m (vitrinite reflec-2.3 Principle and methodology tance equivalent from 1.3% to 1.4%), and among them, fluo- rescence, oil stain and oil shows can be found easily. Pang et al. (1993, 2005) and Pang (1995) discussed the con- cept of hydrocarbon expulsion threshold based on mass bal- ance theory which mean the sum of hydrocarbon generation, 2.2 Experiments and data reservation and expulsion keeps constant in a source rock system. The expulsion threshold is defined as a quantity of QA/QC were preliminarily conducted on samples to ensure hydrocarbon generated in a source rock system, at which the the representativeness and free of contaminations from arti- induced over-pressure caused by fluid expansion exceeds facts. During sample preparation, the samples were cleaned capillary force and causes massive hydrocarbon migration first with distilled water in order to dispel any annexing out of the source rock into carrier beds under a new hydro- agents from drilling mud. The samples were crushed to 80 dynamic equilibrium (Pang et al. 1993, 2005; Pang 1995) mesh after drying for 5 h at 55 °C and then sealed in glass (Fig. 2). Thus, an effective source rock is defined the one bottles for further examinations. that has expelled large quantity of hydrocarbon fluids and Two laboratory experiments are conducted in this study: the expulsion threshold is used to identify effective source TOC content analysis and Rock–Eval pyrolysis. In order to rock. The expulsion threshold can be described by geologi- guarantee experimental quality, a finely GBW(E)070037a cal conditions such as depth (H), organic type, thermal matu- sample in powder form with TOC of 2%, S of 8.2 ± 0.3 mg/g rity (R ) and organic abundance (TOC), critical saturation 2 o and T of 439 ± 2 °C was selected as the standard. To keep of expulsion (S ). All definitions of the variables mentioned max o the consistency, the standard sample was analyzed both at in this study are introduced in the Table 2. commence and end of each batch of samples as well as In the Middle–Upper Ordovician case study of the Tarim between every five samples within each batch. Basin, the determination of effective source rock is based In the TOC analysis, each sample was taken weighted on the balance between quantity of hydrocarbon generated 100 mg and the CS-230HC machine produced by LECO and quantity of hydrocarbon required by primary migration Company of USA was utilized. Dilute hydrochloric acid was (Pang et al. 1993, 2005; Pang 1995). If the quantity of hydro- dripped onto the samples to get rid of inorganic carbons until carbon generated is reached or greater than the expulsion no bubbles were formed. And then distilled water was used threshold, the source rock is regarded as effective that con- to rinse simples multiple times for neutralizing hydrochloric tributed to hydrocarbon accumulation in the region. In this acid in the samples. Finally, those samples were exsiccated paper, the expulsion threshold is estimated from a statistical at a low temperature around 40  °C and incinerated with model that was established on large number of observations oxygen at a high temperature for the conversion of TOC in well-studied petroleum-bearing sedimentary basins in content to CO . Infrared detector was used to measure the China (Pang et al. 2005). The hydrocarbon expulsion thresh- S experimental signal. old is determined where the hydrocarbon generation poten- In order to conduct Rock–Eval pyrolysis experiment, tial in Fig. 2, the envelope curve of data points of ((S + S )/ 1 2 the amount of free S and pyrolyzed hydrocarbons and the TOC) × 100, reaches its maximum value (Pang et al. 2005). highest pyrolysis temperature (T ) can be acquired by When source rocks are buried deeper than the hydrocarbon max Rock–Eval 6 instrument. The beginning temperature of expulsion threshold, hydrocarbons are expelled from source pyrolysis procedure was set to be 300 °C and held for 3 min. rocks, and the hydrocarbon generation potential decreases Further, the increasing rate of temperature was set at 25 °C (Chen et al. 2020). 1 3 Petroleum Science (2020) 17:1491–1511 1495 3 3 3 Hydrocarbon amount per volume of rock (Q, kg/m or m /m ) m , is quantity of liquid residual hydrocarbon in a single unit volume of rock at expulsion threshold; Q , kg/m , is rag quantity of absorbed gas in a single unit volume; Q , kg/ rwg m , is quantity of water-soluble gas in a single unit volume; and Q , kg/m , is quantity of oil-soluble gas in a single unit rog volume. All the quantities are measured at the expulsion Residual hydrocarbon Q < Q r rm threshold in source rock. curve (1) Calculation of liquid hydrocarbons (Q ) at expulsion ro 2000 threshold Pang et al. (1993) analyzed the liquid residual hydrocarbons Hydrocarbon expulsion Q = Q r rm in source rocks and their relationship with major geologi- threshold Qrag cal controlling factors based on the real data from Songliao 3000 rwg Qrog Basin, Hailaer Basin and Tarim Basin in China and estab- ro lished a statistical model for estimating the quantity of liq- uid residual hydrocarbons at the expulsion threshold in the source rock. The model has the following form: Q ≥ Q r rm Hydrocarbon generation Q =  ⋅ ( +Δ) ⋅ S (2) ro o n om curve � 2 − (R −R ) ∕D n o S = f (C%) ⋅ e ∕(1 − B ) (3) om k Qrm Q f (C) = A + A ⋅ C + A ⋅ (C) (4) 0 1 2 Residual Residual water Residual oil absorbed gas soluble gas soluble gas Expelled 2 Residual oil B = 0.81 − 1.05R + 0.18(R ) (5) hydrocarbon k o o where φ , %, is porosity in normal compaction state; Δφ Fig. 2 Mass balance model of hydrocarbon generation, residue, is residual porosity in under compacted state; S , %, is expulsion variation of source rock (modified from Pang et al. 1993). om Before hydrocarbon expulsion threshold, all of the hydrocarbons are saturation of liquid residual hydrocarbon in source rock. retained in source rock since the fluids are not enough to be able to f(C) is correlation factor of organic matter abundance and migrate against capillary sealing; at the hydrocarbon expulsion liquid residual hydrocarbon amount in source rock; B , %, threshold, fluids in source rock are sufficient to trigger the secondary represents the proportion of light hydrocarbons in liquid migration and the expulsion amount is zero; after the hydrocarbon expulsion threshold, source rock expels movable hydrocarbons, and hydrocarbons; C, %, represents organic matter content; R , expulsion amount would increase with growing maturity and might %, represents vitrinite reflectance; ρ , kg/m , is density of gradually decrease when exhausting its ability to generate hydrocar- liquid residual hydrocarbons; A , A , A , D and R’ are unde- o 1 2 bons either through lack of sufficient organic matter or due to reach- termined constants concerning the characteristics of the ing an over mature state source rocks in the study area. (2) Calculation of absorbed gas at expulsion threshold (Q ) rag 2.4 Model for calculating hydrocarbon expulsion The absorbed gas at expulsion threshold can be estimated threshold using the following expression: According to the previous study (Pang et al. 1993, 2005; Pang 1995; Jiang et al. 2002, 2006), residual hydrocarbons Q = Q ⋅  (6) rag rai g in source rocks mainly include liquids, free and adsorbed i=1 gases, water-soluble and oil-soluble gases (Fig. 2, Eq. 1): 3 3 where Q, m /m , is quantity of residual absorbed hydrocar- rai Q = Q + Q + Q + Q bon component i in a signal unit volume of rock; i represents rm ro rag rwg rog (1) th the i component of gaseous hydrocarbons, such as CH , where Q , kg/m , is quantity of hydrocarbon in a single rm C H, C H ; ρ , kg/m , is density of gaseous hydrocarbons. 2 6 3 8 g unit volume of source rock at expulsion threshold; Q , kg/ ro 1 3 Paleo depth of source rock during evolution (H, m) 1496 Petroleum Science (2020) 17:1491–1511 The amount of absorbed gas is mainly related to source Q = Q ⋅ (13) rock properties (organic matter abundance, organic matter rwg rwgi g i=1 type, organic matter maturity, mineral components and specific surface areas), formation pressure and temperature, gaseous hydrocarbon components and concentration and other factors Q = q (i) ⋅  ⋅ 1 − S (14) rwgi w o (Dubinin 1960; Schettler et al. 1991; Robert and Zoback 2014; 3 3 where Q, m /m , is water-soluble hydrocarbon compo- Ross and Bustin 2009). Pang et al. (1993) analyzed the influ- rwgi nent i in pore water; i represents different components of ence of each of the factors in a relation to the absorbed hydro- gaseous hydrocarbons such as CH , C H, C H ; ρ , kg/m , carbon component i based on the data collected from Songliao 4 2 6 3 8 g 3 3 is density of gaseous hydrocarbons; q (i), m /m , is solu- Basin, Hailaer Basin and Tarim Basin in China. An empirical w ble gaseous hydrocarbon component i amount in formation model was established to simulate the amount of absorbed water; φ, %, is source rock porosity; S , %, is fluid residual gas component i amount. The model can be expressed quan- o hydrocarbon flow saturation in source rock. titatively in the following equations (Pang et al. 1993; Tian In their study, an empirical model was also established et al. 2010): to estimate gas component i amount in formation water, −n(T−20) Q = K ⋅  ⋅ K(C%) ⋅ K R ∕K ⋅ a ⋅ b ⋅ P ⋅ e ∕(1 + b ⋅ P) rai i r o w i i i which is displayed as follows (Pang et al. 1993; Tian et al. (7) 2010). n = 0.02∕(0.993 + 0.0017P) (8) q (i)= q (1, T, P, X ) ⋅ q (i, T, P)∕q (1, T, P) (15) w w K w w K R = 0.836 + 0.68 R + 0.498 R 1.33 (9) o o o q 1, T, P, X = 1.15 ⋅ 0.005 ⋅ T ⋅ 22.4∕16 w K ⋅ 0.994 − 0.0032 ⋅ X + 0.0007 ⋅ T K(C) = B + B ⋅ C (10) 0 1 (16) 2 2 1−P q (i, T, P) = a + a ⋅ P + a ⋅ T + a ⋅ P + a ⋅ T + a ⋅ P ⋅ T w 0i 1i 2i 3i 4i 5i K = 1 + 0.445e (11) (17) ⎧ ⎧ ⎧ 0.079 0.117 5.32 CH a = 2.416 a = 1.229 a = 0.231 ⎧ ⎧ ⎧ ⎧ 4 01 02 03 ⎪ ⎪ ⎪ ⎪ ⎪ ⎪ ⎪ 0.00478 0.723 0.15P + 0.30 C H a = 0.00961 a = 0.00137 a = 0 2 6 ⎪ 11 ⎪ 12 ⎪ 13 K = a = b = i = ⎨ ⎨ ⎨ ⎨ i i i 0.0066 1.309 3.04P + 0.6858 C H ⎪ ⎪ ⎪ a =−0.0348 a =−0.0175 a = 0 3 8 21 22 23 ⎪ ⎪ ⎪ ⎪ ⎨ ⎨ ⎨ −5 −6 −6 ⎩ 0.0038 ⎩ 1.833 ⎩ 8.688P + 1.065 ⎩ C H a =−1.04 × 10 a =−3.87 × 10 a =−3.31 × 10 4 10 31 32 33 ⎪ ⎪ ⎪ −7 −7 −7 (12) a = 9.05 × 10 a = 3.94 × 10 a = 4.26 × 10 ⎪ ⎪ ⎪ 41 42 43 −5 −5 −5 ⎪ ⎪ ⎪ a = 6.14 × 10 a = 3.27 × 10 a = 1.141 × 10 51 52 53 where n means correlation factor related to pressure, as an ⎩ ⎩ ⎩ (18) integer; T, °C, represents formation temperature; P, Pa, is 3 3 formation pressure; C, %, refers to organic matter content; where q (i), m /m , is soluble gaseous hydrocarbon com- R , %, means vitrinite reflection; K is wettability, dimen- o w ponent i amount in formation water; T, °C, represents the sionless; K(C) is correlation factor between organic matter formation temperature; P, MPa, is the formation pressure; abundance and absorbed gas amount in source rock; K(R ) o X , g/L, means salinity of formation water; q (1, T, P, X ) K w K is correlation factor between thermal maturity and absorbed is variance of methane solubility in water controlled by pres- gas amount in source rock; K is correlation factor between i sure, temperature and water salinity; q (1, T, P) is solubil- hydrocarbon component and absorbed gas amount in source ity of gaseous hydrocarbon component i in pore water con- th rock; i represents the i component of gaseous hydrocarbons trolled by pressure, temperature and water salinity. such as CH , C H, C H and C H ; ρ , kg/m , is density of 4 2 6 3 8 4 10 r source rocks; and B and B are related coefficients for the 0 1 (4) Calculation for oil-soluble hydrocarbon (Q ) at expul- rog relationship between absorbtion ability of source rocks and sion threshold organic carbon content. The calculation model of oil-soluble gas amount can be (3) Calculation of water-soluble gas (Q ) at expulsion rwg expressed as follows: threshold. Q = Q ⋅  (19) rog rogi g The calculation model of water-soluble gas can be i=1 expressed as follows: 1 3 Petroleum Science (2020) 17:1491–1511 1497 solvent, the unit being a proportion of the weight of extrac- Q = q (i) ⋅  ⋅ S rogi o o (20) tion to that of rock. ‘S ’ is measured hydrocarbons from 3 3 where Q, m /m , is quantity of oil-soluble hydrocarbons Rock–Eval pyrolysis when the rock is heated at 300 °C. rogi component i in pore oil; i represents component of gaseous However, these two approaches for measuring actual resid- 3 3 3 hydrocarbons such as CH , C H, C H , kg/m ; q (i), m /m , ual hydrocarbon amount are not perfect. During the sam- 4 2 6 3 8 o is quantity of gaseous hydrocarbons component i dissolved pling and sample preparation, gaseous residual hydrocar- in liquid hydrocarbons; φ, %, is source rock porosity; S , %, bons are inevitably easily lost on the surface (Jiang et al. is fluid residual hydrocarbon flow saturation in source rock. 2016). Therefore, gaseous hydrocarbons amount in rock is Previous study shows that pore pressure and formation mostly not included in the parameters ‘A’ or ‘S ’. Further- temperature are the two major geological factors controlling more, change in temperature and pressure causes certain the amount of residual oil-soluble gaseous hydrocarbons. light liquid hydrocarbons to be released, especially those Based on the findings, Pang et al.(1993) built a correspond- with carbon atoms fewer than 15. In conclusion, residual ing model to simulate residual gas constituent i amount in oil hydrocarbons contained in ‘S ’ and ‘A’ are only a portion per volume of rock based on the experiments and study that of actual residual hydrocarbons in rocks. The components is displayed as follows (Pang et al. 1993; Tian et al. 2010). and loss amount vary with different lithologies. The maxi- mum hydrocarbon evaporative loss rate can be up to 80% q (i)= 4.95 ⋅ K(i) ⋅ K( ) ⋅ q (T, P) o o og (21) (R ≤ 1.3%) by Chen et al. (2018) of Type I kerogen. The study result is consistent with that by Xue et al. (2016) of K(i) = (A(i) + B(i) ⋅ P)∕100 76% loss rate through kinetic study of hydrocarbon genera- (22) tion. When R > 1.3%, the hydrocarbon evaporative loss rate would increase with increasing R as more oil crack to gas- K  = 1.75 − 1.8 ⋅ (23) o o eous and light hydrocarbons that are more susceptible to evaporative loss. In addition, compared to ‘A’, ‘S ’ contains q (T, P)=−0.726 + 0.387 ⋅ P − 0.0323 ⋅ T og (24) more scarce residual hydrocarbons, as a consequence of ‘S ’, representing only the hydrocarbons released before heating A(1) = 62.63 B(1) = 0.00716 at 300 °C, while constituents with larger molecular weight ⎧ ⎧ ⎪ ⎪ or high polarity remain in the rocks. Therefore, light hydro- A(2) = 18.68 B(2) = 0.00365 (25) ⎨ ⎨ A(3) = 9.89 B(3) = 0.00212 carbon compensation calibration is necessary to offset these ⎪ ⎪ ⎩ ⎩ losses when calculating actual residual hydrocarbon amount A(4) = 4.203 B(4) = 0.00085 using ‘A’ and ‘S ’. 3 3 where q (i), m /m , is quantity of gaseous hydrocarbons The actual residual hydrocarbons amount (Q ) was calcu- component i dissolved in liquid hydrocarbons in a signal lated according to ‘S ’ in this study based on the Rock–Eval 3 3 unit volume; q (T, P), m /m , is the gaseous hydrocarbon og pyrolysis results of representative samples chosen. The light in liquid hydrocarbons, an empirical function of temperature hydrocarbons component was compensated in ‘S ’ accord- and pressure conditions; K(i) is proportion of component i ing to Pang et al. (1993), and the amount of actual residual of gaseous hydrocarbons dissolved in liquid hydrocarbons, hydrocarbons was calculated, utilizing the calibrated resid- decimal; K(ρ ) is calibration factor reflecting variation of ual amount (S ) according to the equations displayed as 1+ oil-soluble gaseous hydrocarbons with oil density, as an follows: integer; ρ , kg/m , is density of gaseous hydrocarbons; T, S = S ∕(1 − B ) °C, represents the formation temperature; and P, Mpa, rep- (26) 1+ 1 k resents the formation pressure. Q = S ⋅ (27) r 1+ r 2.5 Model for calculating actual residual where S , mg/g, is actual residual liquid hydrocarbon 1+ hydrocarbon amount amount considering light hydrocarbons; S , mg/g, is the free hydrocarbon amount acquired through pyrolysis experi- Generally, chloroform bitumen ‘A’ and ‘S ’ obtained through ments; B , %, refers to percent by weight of light hydrocar- extraction and pyrolysis experiments were used to represent bons in entire liquid hydrocarbon; as shown in Eq. 5; ρ , kg/ actual residual hydrocarbon amount. Chloroform ‘A’ refers m , is the density of source rocks. to residual hydrocarbons extracted by chloroform organic 1 3 1498 Petroleum Science (2020) 17:1491–1511 source rock density, formation temperature, formation pres- 3 Results sure, oil saturation and formation water salinity. 3.1 Parameters for study area (1) Crude oil density There are some essential geological parameters data for the Increase in depth leads to a rise in formation temperature, simulation of theoretical residual hydrocarbon amount at which leads to a decreasing trend of crude oil density (Fig. 3a). expulsion threshold and calculation of actual residual hydro- The relationship between oil density and depth can be fitted as carbon amount, including crude oil density, porosity, total follows, according to 893 measured crude oil density data from organic carbon, vitrinite reflectance, natural gas density, carbonate reservoirs in Tarim Basin’s platform: Density, g/cm TOC, % VR , % (a) (b) (c) (d) 00.5 1.01.5 00.5 1.01.5 00.5 1.01.5 Porosity (%) 0 6400 5,500 05 10 15 20 N=785 5,600 N = 893 N = 86, N = 14, YW2 well LN46 well logging porosity 5,700 P50 5,800 4000 6460 5,900 6480 y = 805.36ln(x) + 5955.1 R = 0.7427 6,000 7000 6,100 8000 6520 6,200 Formation water Pressure, MPa Temperature, °C Oil sauration,% salinity, g/L (e) (f) (g) (h) 020406080 050 100 150 200 0306090 120 0 100 200 300 0 0 0 0 Formation pressure 1000 1000 1000 1000 N = 324 N = 134 N = 122 N = 495 2000 2000 2000 2000 y = 68.57x + 928.32 3000 3000 R = 0.7792 3000 3000 4000 4000 4000 4000 5000 5000 5000 5000 6000 6000 y = 50.647x - 1479.5 6000 6000 7000 7000 R = 0.7435 Hydrostatic pressure 7000 8000 7000 8000 1.0 (i) (j) Confirmed source rock Confirmed source rock 0.8 N = 56 N = 13 y = 0.024x - 0.057x + 0.026 2 5 R = 0.684 0.6 y = 0.7304x + 0.3244 R = 0.8147 0.4 0.2 0 0 012345 6 0246 81012 TOC, % TOC, % Fig. 3 Parameters of carbonate rocks in the platform of Tarim Basin. a Relationship between oil density and depth; b relationship between porosity and depth; c relationship between TOC and depth of YW2 well; d relationship between VRE and depth of carbonate rocks in LN46 well; e relationship between pressure and depth; f relationship between temperature and depth; g relationship between oil saturation and depth; h relationship between formation water salinity and depth; i relationship between “A” and TOC of confirmed typical source rock; j relationship between gas absorption amount and TOC of confirmed typical source rock (absorption experiment data) 1 3 Depth, m Depth, m Chloroform asphalt “A”, % Depth, m Depth(m) Depth, m Depth, m Absorption amount gas, m /t Depth, m Depth, m Petroleum Science (2020) 17:1491–1511 1499 −6 feature (Fig. 3e). The relationship between formation pres- =−7.7 ∗ 10 H + 0.88 (28) sure and depth in Tarim Basin’s platform is obtained based where ρ , g/cm , is crude oil density; and H, m, refers to on 324 measured formation pressure data with different depth. depths, which is displayed as follows. P = 0.011H − 0.416 (32) (2) Porosity where P, MPa, is pressure, and H, m, refers to depth. Along with increasing depth, the porosity of carbonate rocks in Tarim Basin’s platform present two relative large (6) Temperature areas, in which the porosity values gradually increase to a maximum due to karstification under unconformity sur - In general, temperature increases linearly with depth faces (Lin et al. 2012) and carbonate rock dissolution by (Fig. 3f). The formation temperature of Tarim Basin’s plat- acidoid since hydrocarbon was generated and expelled form can be calculated according to 134 actual tempera- (Surdam et al. 1984; Eseme et al. 2012) then decreases to ture data with different depth. The relationship between a normal matrix porosity (Fig. 3b). The relationship can be temperature and depth is displayed below: obtained by 785 logging porosity data of local dry layers T = 0.014H + 52.31 (33) with different depth in Tarim Basin’s platform, and it can be fitted as per the two binomials: where T, °C, is temperature; and H, m, refers to depth. −6 2 −2 𝜑 = 2.2 × 10 H + 1.7 × 10 H − 28.63,H < 5100 (29) (7) Oil saturation −6 2 −2 = 3.1 × 10 H + 3.6 × 10 H − 101.35,H ≥ 5100 (30) As shown in Fig.  3g, with increasing depth porosity decreases and oil saturation increases. According to 122 where φ, %, is formation porosity; and H, m, refers to depth. measured data with different depth, the relationship was determined in Tarim Basin’s platform as below: (3) TOC S = 0.5608 ⋅ ln(H)− 4.074 (34) The total organic carbon (TOC) data of source rocks where S , %, is oil saturation; and H, m, refers to depth. were obtained from 86 measured data by the experiment designed during the study (Fig.  3c); the location and (8) Formation water salinity experimental methods are shown in Sect. 2.1. It can be easily seen that formation water salinity (4) Vitrinite equivalent increases with depth in Tarim Basin’s platform (Fig. 3h). Due to lack of data on source rock water salinity, that of There is an obvious relationship between vitrinite equivalent reservoir rocks could be used, while carbonate rock is (VR ) and depth of marine source rocks in Tarim Basin plat- both source rock and reservoir. The following equation form, wherein VR appears to exponentially increase with describes the relationship between formation water salin- depth (Fig. 3d). Due to lack of measured values for vitrinite ity and depth, based on 494 measured formation water equivalent of YW2 well, that of LN46 well was used, since salinity data: which is located in the Tabei Uplift and displays the same tectonic setting as YW2 well. The relationship between VR 0.0003H X = 25.563e (35) and depth is well fitted by using 14 practically measured vitrinite equivalent data from LN46 well in the Tabei Uplift, where X , g/L, is formation water salinity, and H, m, refers which can be expressed as: to depth. 0.00092H VR = 0.00405e (31) (9) Other parameters and coefficients where VR , %, is vitrinite equivalent, and H, m, refers to Other parameters used for calculations were adopted from depth. empirical data of Tarim oilfield. For example, natural gas density is taken at an average of 0.71 kg/m ; bulk rock den- (5) Pressure sity 2.6 g/cm is adopted as carbonate source rock density value; normal temperature in the study area is considered The carbonate Cambrian and Ordovician Systems in Tarim as 20 °C. Basin show a normal pressure and a little overpressure 1 3 1500 Petroleum Science (2020) 17:1491–1511 As mentioned above, there are many characteristics in The source rock properties (organic matter abundance, source rock, including source rock lithology, mineral con- organic matter type, organic matter maturity, mineral com- stituent, specific surface area and TOC which is only one ponents and specific surface areas) also control the amount of the factors that control residual oil hydrocarbon amount of absorbed gas (Dubinin 1960). Parameter K(C) is set to (Tissot and Welte 1984). In order to serviceably describe the describe the absorbtion ability of source rocks with differ - retention characteristics of source rocks in the study area, ent organic carbon abundances, and B and B are related 0 1 f(C) is set to characterize the residual capacity of source coefficients for the linear relationship between absorbtion rocks with different TOC, and A , A and A are empiri- ability of source rocks and TOC in the study area. A total of 0 1 2 cal constants in study areas related to f(C). They are calcu- 14 data from typical source rocks interval were selected to lated by simulation and statistical analysis of actual residual determine B and B . The typical source rock interval was 0 1 hydrocarbon amount in source rocks. A total of 56 data from the one confirmed that a large amount of hydrocarbon expul- typical source rocks interval were selected to calculate and sion have occurred. The data were from adsorption experi- determine A , A and A in the study area. The typical source mental results by the Tarim Oilfield Company, PetroChina. 0 1 2 rock data were confirmed that massive hydrocarbon expul- According to the relationship, B = 0.324 and B = 0.730 can 0 1 sion has occurred (Li et al. 2015). The 56 data are from be obtained (Fig. 3j), respectively. PetroChina Tarim Oilfield Company. According to the bino- mial (Fig. 3i), A = 0.026, A = −  0.057, A = 0.024 can be 3.2 Calculation results of hydrocarbon amount 0 1 2 determined for Eq. (4). D refers to variance of the 56 TOC at expulsion threshold data, and D = 0.0163 is determined for Eq. (3). R’ is the gen- eral hydrocarbon expulsion threshold of the source rocks in All parameters and coefficients obtained above were substi- Tarim Basin, and R′= 0.95% is determined for Eq. (3) (Pang tuted in each calculation model, through which the hydro- et al. 2012). carbon amount at expulsion threshold was determined for 3 3 3 3 3 Q , kg/m Q , m /m Q , m /m ro rag rwg (a) (b) (c) 0.095 0.100 0.105 0.110 0.352 0.353 0.354 0.355 0.356 0.357 0.0019 0.00195 0.00200 0.002050.0021 0.090 6400 6400 6400 N =86, YW2 well N =86, YW2well N =86, YW2well 6410 6410 6410 6420 6420 6420 6430 6430 6430 6440 6440 6440 6450 6450 6450 6460 6460 6460 y =32104x - 4896 R =0.7763 6470 6470 6470 y = -6953.22x + 7148.73 y = -567561.24x +7591.46 6480 6480 6480 2 2 R =1.00 R = 0.99 6490 6490 6490 6500 6500 6500 Qro Qrag Qrwg 6510 6510 6510 3 3 3 3 Q , m /m Q , kg/m Q , kg/m rog rg rm (d) (e) (f) 0.075 0.080 0.085 0.090 0.306 0.308 0.310 0.312 0.314 0.4000.405 0.4100.415 0.420 6400 6400 6400 N =86, YW2 well N =86, YW2well N =86, YW2well 6410 6410 6410 6420 6420 6420 6430 6430 6430 6440 6440 6440 6450 6450 6460 6460 6460 y = -4390.58x +8251.56 R = 0.70 6470 6470 6470 y = -9255.07x + 7197.82 R = 0.99 y = -16591x +11589 6480 6480 6480 R =0.9982 6490 6490 6490 6500 6500 6500 Qrog Qrg Qrm 6510 6510 6510 Fig. 4 Relationship of residual hydrocarbon amount and depth of YW2 well, Tarim Basin. a Liquid hydrocarbon amount; b absorbed gas amount; c water-soluble gas amount; d oil-soluble hydrocarbon amount; e gaseous hydrocarbon amount; f total hydrocarbon amount 1 3 Depth, m Depth, m Depth, m Depth, m Depth, m Depth, m Petroleum Science (2020) 17:1491–1511 1501 the case study of YW2 well. Results indicate that hydro- carbonate source rocks (Liu et al. 2017). This is consistent carbon amounts at expulsion threshold of liquid, and gas with the study results by Peters and Moldowan (1993) on soluble in oil and water, decrease linearly with increasing the oil characteristics from marine carbonate source rocks. depths (Fig. 4a, c, d), while gas adsorption in rocks increases Compared with mudstone, the threshold of TOC value with depth (Fig. 4b). However, in general, the total gaseous as an effective source rock of carbonate rock is generally hydrocarbons and the total hydrocarbons at expulsion thresh- smaller. On the one hand, the adsorption and retention old decrease linearly with increasing burial depth (Fig. 4e, capacities of carbonates are weaker than clays (Tissot and f). The hydrocarbon amount at expulsion threshold based on Welte 1984), resulting in a less minimum generation amount modeled parameter values and actual TOC data varies from to expel hydrocarbons. Pyrolysis experiments also clearly 3 3 0.402 kg/m to 0.418 kg/m , with a mean value of 0.410 kg/ manifested that clay-rich rocks can retain a significantly 3 3 m , among which the absorbed gas amounts from 0.352 m / greater quantity of hydrocarbons than carbonate source 3 3 3 m to 0.356  m /m , the water-soluble gas amounts from rocks (Katz 1983). On the other hand, different from marl 3 3 3 3 0.0019 m /m to 0.0021 m /m , the oil-soluble gas amounts source rocks, bioprecursors of carbonate source rocks are 3 3 3 3 from 0.076 m /m to 0.082 m /m , and the oil amounts from mainly plankton assemblages (Liu et al. 2017) with high 3 3 3 0.064 kg /m to 0.106 kg/m (Table 3). hydrocarbon transformation ratio, resulting in low present- day TOC values remaining in the source rocks. Type I and 3.3 Calculation results of actual residual Type II kerogens (regardless of the weight of TOC, their hydrocarbon amount hydrocarbon yield are significantly higher) are, in general, more easily found in carbonates than in siliciclastic facies Actual residual hydrocarbon amount in Middle–Upper Ordo- (Hunt 1967). Additionally, different from mudstones, the vician source rocks in YW2 well can be estimated by using mineral constituent of carbonate source rocks has specialty these parameters and Rock–Eval pyrolysis data (S ) (Fig. 5), that during geological process, hydrocarbons, aqueous car- 3 3 and the amount lies between 0.034 kg/m and 2.953 kg/m boxylic acids and carbon dioxide produced by hydrolytic (Table 3). disproportionation may reach a state of invertible metastable thermos dynamic equilibrium, including sedimentary min- 3.4 Identification results of effective source rocks erals such as calcite (Helgeson et al. 1993; Jeffrey 2003), forming carboxylate salts with the structure compatible Based on the above method and calculation results, it can in carbonate minerals and then preserved in the carbonate be determined whether hydrocarbon expulsion has occurred source rocks. These carboxylate salts widely distributed in in Middle–Upper Ordovician interval of YW2 well. Results marine carbonate source rocks, keep stable in low tempera- indicate that hydrocarbon expulsion took place in carbon- ture and have certain hydrocarbon generation capability at ate source rocks which have a low value of T OC in the high evolution stage (Carothers and Kharaka 1978; Vande- pd Yijianfang formation between 6452 m and 6487 m (Fig. 6). grift and Horwitz 1980; Liu et al. 2017). Since during our traditional TOC values tests inorganic carbon contents are removed by dripping diluted hydrochloric acid, the organic 4 Discussion carbon contents of carboxylate salts would be easy to lose leading to the underestimate of TOC values and hydrocarbon Early in 1933, Trask pointed out the hydrocarbon genera- generation potential at high evolution stage (Liu et al. 2016). tion capacity of carbonate rocks. In the following decades, However, the loss of organic carbon affects more lightly to people gradually began to pay attention to carbonate rock the TOC test of muddy source rocks, since the contents of series and carried out a series of targeted research work. acid-soluble carbonate minerals of them are low and the The studies effectively guided oil and gas exploration, and a partial acidic environment where muddy source rock formed number of large and medium oil and gas fields contributed is not beneficial for the formulation of carboxylate salts (Liu by carbonate source rocks were successfully discovered. et al. 2017). For example, the Paleozoic strata in the Williston Basin are almost composed of limestone, dolomite and evaporate, with 4.1 Hydrocarbons self‑generated and retained very few argillaceous rocks. Its oil and gas mainly come in samples from the Red River, Winnipegosis, Bakken and Lodgepole Formation of the Upper Ordovician–Lower Carboniferous Due to the particularity of lithology, carbonate rocks can (Tao et al. 2013). The organic geochemical indexes of oils act as source rocks to provide hydrocarbons as well as res- in the Tahe Oilfield in the Tarim Basin show the ratio of C ervoir rocks to provide storage for hydrocarbon accumula- hopane/C hopane over 0.6 and C S hopane/C S hopane tion (Trask 1933; Li et al. 1998; Wang et al. 2016; Liu et al. 30 35 34 over 0.8, indicating obvious characteristics of derived from 2017). Therefore, it is essential to ensure the hydrocarbons 1 3 1502 Petroleum Science (2020) 17:1491–1511 Table 2 Summary table of definitions of the variables Variable Definition Unit Q The actual residual hydrocarbons amount kg/m Q The quantity of hydrocarbon in a single unit volume of source rock at expulsion threshold kg/m rm Q The quantity of liquid residual hydrocarbon in a single unit volume of rock at expulsion threshold kg/m ro Q The quantity of absorbed gas in a single unit volume kg/m rag Q The quantity of water-soluble gas in a single unit volume kg/m rwg Q The quantity of oil-soluble gas in a single unit volume kg/m rog 3 3 Q The quantity of residual absorbed hydrocarbon component i in a signal unit volume of rock m /m rai 3 3 Q Water-soluble hydrocarbon component i in pore water m /m rwgi 3 3 Q The quantity of oil-soluble hydrocarbons component i in pore oil m /m rogi i The ith component of gaseous hydrocarbons such as CH , C H, C H and C H 4 2 6 3 8 4 10 φ Source rock porosity % φ Porosity in normal compaction state % Δφ Residual porosity in under compacted state % S Fluid residual hydrocarbon flow saturation in source rock % S Saturation of liquid residual hydrocarbon in source rock % om f(C) Correlation factor of organic matter abundance and liquid residual hydrocarbon amount in source rock B The proportion of light hydrocarbons in liquid hydrocarbons % C Organic matter content % R Vitrinite reflectance % ρ Density of liquid residual hydrocarbons kg/m ρ Density of source rocks kg/m ρ Density of gaseous hydrocarbons kg/m A , A , A , D and R′ Constants concerning the characteristics of the source rocks in the study area 0 1 2 n Correlation factor related to pressure T Formation temperature °C P Formation pressure Pa or MPa K Wettability K(C) Correlation factor between organic matter abundance and absorbed gas amount in source rock K(R ) Correlation factor between thermal maturity and absorbed gas amount in source rock K(i) Proportion of component i of gaseous hydrocarbons dissolved in liquid hydrocarbons K(ρ ) Calibration factor reflecting variation of oil-soluble gaseous hydrocarbons with oil density, as an integer K Correlation factor between hydrocarbon component and absorbed gas amount in source rock B B Related coefficient for the relationship between absorbtion ability of source rocks and organic carbon 0 1 content X Salinity of formation water g/L 3 3 q (i) Soluble gaseous hydrocarbon component i amount in formation water m /m q (1, T, P) Solubility of gaseous hydrocarbon component i in pore water controlled by pressure, temperature and water salinity q (1, T, P, X ) Variance of methane solubility in water controlled by pressure, temperature and water salinity w K 3 3 q (i) Quantity of gaseous hydrocarbons component i dissolved in liquid hydrocarbons m /m 3 3 q (T, P) The gaseous hydrocarbon in liquid hydrocarbons, an empirical function of temperature and pressure condi- m /m og tions S Actual residual liquid hydrocarbon amount considering light hydrocarbons mg/g 1+ S Free volatile hydrocarbons thermally flushed from a rock sample at 300 °C mg/g S Products that crack during standard Rock–Eval pyrolysis temperatures (300–650 °C) mg HC/g rock H Depth m T The highest pyrolysis temperature °C max TOC Total organic carbon wt% TOC Initial TOC content wt% TOC Present-day TOC wt% pd 1 3 Petroleum Science (2020) 17:1491–1511 1503 Table 2 (continued) Variable Definition Unit VR Vitrinite equivalent % (a) S , mg/g 00.2 0.40.6 0.81.0 N =86, YW2 well (b) Sample temperature, °C 102389 645159 434 708 840 Oxidation FID signal Sample temperature IR CO signal IR CO signal 0 371 0102030405060 70 Time, min Well Sample Depth, mWeight, mg S1, mg/g S2, mg/g TOC, % Tmax, °C YW2C-625221 6454 71.0 0.58 0.52 0.275 462 (c) Sample temperature, °C 103383 644159 434 707 840 Oxidation FID signal Sample temperature IR CO signal IR CO2 signal 6 544 0102030405060 70 Time, min Well Sample Depth, mWeight, mg S , mg/g S , mg/g TOC, % T , °C 1 2 max YW2C-625224 6468 71.3 0.50.48 0.287 464 Fig. 5 a Relationship between S and depth of YW2 well in the platform of Tarim Basin; b pyrogram of low-TOC samples with depth of 1 pd 6454 m; and c pyrogram of low-TOC samples with depth of 6468 m from the Middle–Upper Ordovician Formation in the YW2 well, Tarim pd Basin 1 3 FID signal millivolts, FID FID signal millivolts, FID Depth, m IR CO signal mv IR CO signal mv 2 1504 Petroleum Science (2020) 17:1491–1511 TOC of effective S of effective Porosity of effective source rock, % Q , kg/m source rock, mg/g source rock, % 0 1 0 4 01 0 1.5 TOC of ineffective rock, % 0 1 S of ineffective Porosity of Q , kg/m rock, mg/g rm ineffective rock, % TOC = 0.5% 01 0 1.5 0 1 Lianglitage Upper Tumuxiuke Ordovician Sample1 Sample2 Sample3 Middle Yijianfang Ordovician Sample4 Lower Ordovician Yingshan Mudstone Lime Argillaceous Micritic Powder Oolitic Arenitic Bioclastic FluorescenceOil spot Oil-bearing Sample without Hydrocarbon mudstone limestone limestone crystalline limestone limestone limestone hydrocarbon explusion limestone explusion sample Fig. 6 Distinguish results of effective and ineffective source rocks of Ordovician in YW2 well 0.8 0.7 (a) (b) Ineffective rock Ineffective rock N = 86, YW2 well N = 86, YW2 well Effective source rock Effective source rock 0.7 0.6 0.6 0.5 Population 1 0.5 S /TOC × 100 = 100 0.4 0.4 0.3 0.3 Population 2 0.2 0.2 0.1 0.1 0 0 00.2 0.40.6 0.81.0 00.2 0.40.6 0.81.0 TOC, % TOC, % Fig. 7 S and S characteristics of effective source rocks and ineffective rocks with TOC of YW2 well, Tarim Basin. a S vs TOC; b S vs TOC 1 2 1 2 1 3 S , mg/g System Formation Depth, m Lithology S , mg/g Biomarker location Petroleum Science (2020) 17:1491–1511 1505 are self-generated and retained and exclude those charged to the porosity contrasts of two types of carbonates in from other source rocks when identifying the effectiveness YW2 well. In the process of tight oil charging, it is always of low-TOC abundance source rocks. inf luenced by capillary pressure, viscous force and iner- Several evidences can be obtained to prove the tial force (Zou et al. 2013). Effective reservoirs depict a hydrocarbons in samples of YW2 well are self-gener- lower porosity limit within which the oils can accumulate ated and retained. Firstly, according to the Rock–Eval (Jiang et al. 2017). In Tarim Basin, the effective carbon- pyrolysis experiment results, the effective source rocks ate reservoirs generally have porosity greater than 1.8% with low-TOC generally have characteristics with S / (Pang et  al. 2013). Additionally, the well is located in pd 1 TOC×100 ≥ 100 mg/g TOC, HI (S /TOC×100) ≥ 50 mg/g, the slope adjacent to the depression lack of faults and is and extremely low porosity (Figs. 6 and 7). The relatively developed low permeability (Fig. 1). Thus, the studied high S /TOC values suggest that the actual amount of interval cannot be regarded as effective reservoir rocks residual hydrocarbons is relatively large (Fig. 7a) so that for migrated oils. the kerogens can generate sufficient hydrocarbons to result in enough dynamic force to against the capillary 4.2 Oil–source correlation resistance and expel outward to be referred as effective source rocks. On the other hand, the relatively high value Hydrocarbon expulsion has been identified from the poten- of HI (> 50 mg/g) shows the fact that the kerogen in the tial carbonate source rocks in Middle–Upper Ordovician in source rocks can continue to generate and expel hydro- Tarim Basin. Oils from the Middle–Upper Ordovician source carbons (Fig. 7b). rocks have features including a relatively low amount of Secondly, reservoir porosity in effective source rock gammacerane, 24-isopropylcholestanes, C homohopanes, interval is much higher than those in the non-source rock 24-norcholestanes, C regular steranes and C dinosteranes 28 30 interval. It may be due to the organic porosity present in (4α, 23, 24-trimethylcholestanes) yield a V-shaped regular the effective source rock by hydrocarbon generation and sterane distribution (Zhang et al. 2000, 2002a, 2004; Wang expulsion (Modica and Lapierre 2012; Chen and Jiang and Xiao 2004; Li et al. 2015; Huang et al. 2016). 2016). According to the logging data of the study interval, Based on the characteristics of biomarkers, an oil–source the porosity is poor developed, which ranges from 0.10% correlation was performed between the crude oil samples to 1.34% (Fig. 6). Based on the organic porosity calcula- from discovered oil accumulations and potential effective tion model (Chen and Jiang 2016), the average of esti- carbonate source rocks. Results suggest that there are many mated organic porosity reaches 1.2%, which is accordant similar characteristics between potential effective low-TOC (a) Sample 1 29 (b) Sample 2 YW2, O , 6459.75 m YW2, O , 6448.1 m 2y 2y C C 28 21 (c) Sample 3 (d) Sample 4 YW2, O , 6465.8 m YW2, O , 6475.3 m 2y 2y 21 28 Fig. 8 Regular sterane characteristics of Upper–Middle Ordovician source rocks with hydrocarbon expulsion in YW2 well, Tarim Basin (m/z = 217) (Sample locations are shown in Fig. 6) 1 3 1506 Petroleum Science (2020) 17:1491–1511 27 29 (a) YM2-12-4, O ,5889.09-5985 m 1-2y YM2-12-14, O, 5775.5-5915 m YM2-1H, O , 5918.5-6203 m 2y (b) C 27 H7-2, O , 6534-6595 m 2+3 H9001, O , 6457.9-6680 m 1y XK4, O , 6834.05-6850 m 2y Fig. 9 Oil regular sterane distribution characteristics of Ordovician in Tabei area, Tarim Basin (m/z = 217, and well locations are shown in Fig. 1a). a Crude oil from Yingmaili oilfield; b crude oil from Halahatang oilfield source rocks in well YW2 and crude oils in the Yingmaili residual hydrocarbon amounts of mature source rock inter- and Halahatang oilfields in the Tabei area, including low vals that have expelled hydrocarbons are always greater than C regular steranes and a ‘V’-shaped trend of sterane dis- or equal to critical hydrocarbon amount at expulsion thresh- tribution (C, C and C regular steranes) (Figs. 8 and old (Fig. 10a). 27 28 29 9), which indicate that crude oils may be originated from Furthermore, 43 rock samples were also selected from the effective source rocks with low-TOC abundance in the typical non-source rock (that cannot expel hydrocarbon) Tabei area. intervals of TC1 and TZ10 wells in Tarim Basin (loca- tions are shown in Fig. 1), to compute residual hydrocarbon 4.3 Method verification amounts based on the above-mentioned method and model. Results indicate that of non-source rock interval samples Fifteen samples from typical source rock wells, including incapable of hydrocarbon expulsion, actual residual hydro- KN1, TD1 and TD2 wells (locations are shown in Fig. 1, Li carbon amount is 100% less than critical amount at expul- et al. 2010), were used to verify the above model. Based on sion threshold (Fig. 10b). the method and model, critical and actual residual hydro- Verification results indicate that the proposed method and carbon amounts were calculated. As results indicate, actual models are useful to identify effective source rocks which 1 3 Petroleum Science (2020) 17:1491–1511 1507 100 6 (a) Qr N = 15 Present-day TOC 80 Q rm 50 3 0 0 KN1 KN1 KN1 KN1 TD1 TD1 TD1 TD1TD2 TD2TD2 TD2TD2 TD2TD2 3.0 3.0 (b) Qr N = 43 Present-day TOC 2.5 2.5 Qrm 2.0 2.0 1.5 1.5 1.0 1.0 0.5 0.5 Fig. 10 Relationship between actual and residual hydrocarbon at expulsion threshold amounts of confirmed typical source rocks and non-source intervals, Tarim Basin. a Typical source rocks (well locations are shown in Fig. 1a); b non-source rocks (well locations are shown in Fig. 1a) have expelled hydrocarbons from non-source rocks and can Rock–Eval data, reservoir volumetric parameters, oil den- thus be applied in the identification of effective low organic sity, water salinity, formation pressure and temperature. matter abundance source rock in carbonate successions. This requires the data of the application area is relatively The method proposed in this study takes mass bal- sufficient. Meanwhile, during the process of determin- ance principle as basis, by determining and comparing ing actual residual hydrocarbon amount, we need to iden- the hydrocarbon expulsion threshold and actual residual tify whether the residual hydrocarbons in the sample are hydrocarbon amount, to identify the samples reaching migrated or self-generated. This part is quite essential expulsion threshold as effective source rocks. Compared and needs multiple means to comprehensively identify with traditional methods to identify effective source rocks so as to eliminate the influence of migrated hydrocar- using the present-day TOC values, the proposed method is bons. In addition to the methods discussed in Sect. 4.1 in an innovation. It eliminates the influence of present-day this study, Loucks and Reeds (2014) as well as Li et al. TOC values changing in different evolution stages. The (2018) provided effective methods to identify migrated evaluation method may be more objective, especially for hydrocarbons. the source rocks at high evolution stage, such as those in the Tarim Basin and Sichuan Basin in China. Currently, 4.4 High original TOC and original hydrogen index lacustrine carbonate source rocks have also been noted of effective TOC rocks pd during recent years (Liu et al. 2019). For example, the carbonate source rocks might have act as important oil In this study, the interval depth for samples is 86 m and contributors in the lacustrine Mahu sag (Cao et al. 2019). the value of VR (1.31%–1.41%) is similar; hence, HI at Although the study case in this study is for marine car- present day can be used to differentiate diverse populations bonate rocks, based on the principle and methods of mass of organic matter. Closer examination suggests the presence balance, the identification of effective lacustrine carbon- of two distinct organic matter populations within YW2 sam- ate rocks is also applicable. ples: one population with HI > 50 mg/g and the other with The limitation of the method, as described in meth- HI < 50  mg/g (Fig. 7b). Utilizing the method proposed by odology section, involves many parameters, such as Chen and Jiang (2015) on kerogen kinetics, the original 1 3 3 3 Residual hydrocarbon, kg/m Residual hydrocarbon, kg/m TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 Present-day TOC, % Present-day TOC, % 1508 Petroleum Science (2020) 17:1491–1511 4.5 Probable contribution of lowT ‑ OC source rock Table 3 Calculation results of hydrocarbon amount at expulsion pd threshold and actual residual hydrocarbon amount of Middle–Upper to hydrocarbon resources Ordovician Formation in YW2 well in the platform of Tarim Basin Previous controversy on the source of marine oils in Tarim Amount Minimum Average Maximum Basin’s platform concentrated on different opinions from 3 3 Q, m /m 0.352 0.353 0.356 rag the views of geochemistry and geology. Based on the pre- 3 3 Q, m /m 0.00190 0.00200 0.00210 rwg vious studies on geochemical biomarkers parameters and 3 3 Q, m /m 0.0760 0.0800 0.0820 rog carbon isotope characteristics, it is reported that the marine Q , kg/m 0.0640 0.0970 0.106 ro hydrocarbons mainly come from Middle–Upper Ordovician Q , kg/m 0.402 0.410 0.418 rm source rocks (Zhang et al. 2000, 2002b, 2004, 2007; Wang Q , kg/m 0.0340 0.554 2.953 and Xiao 2004; Zhao et al. 2008; Li et al. 2008; Wang et al. 2014). However, recent data indicate that the organic matter contents of carbonate rocks in the Middle–Upper Ordovician hydrogen index (HI ) of the above two populations is esti- are commonly developed low for the oil/gas accumulations mated and the kerogen types of them are further identified in the basin (Fig. 1). Therefore, the Cambrian–Lower source according to the values of HI . Results show that the HI rocks with high present-day organic matter abundance are 0 0 values of population 1 and 2 are 870 mg/g and 440 mg/g, regarded as the main source for widespread distribution respectively. The kerogens of population 1 are identified of of hydrocarbon accumulations in the carbonate platform Type I and that of population 2 is of Type II. The compo- successions in the basin (Pang et al. 2016). Nevertheless, nents statistical data of optical kerogen organic macerals according to the third round of National resource assessment in well YW2 clarify the fact that there are kerogens from that was based on contribution of high abundance Cambrian pelagic algae with ≥ 80% of sapropelinite and kerogens from source rocks, the predicted in place resources of oil, gas benthic algae with ≥ 20% of provitrinite (similar with vit- and oil equivalent in Tazhong area, is 0.947 × 10   tons, 9 3 8 rinite) (Table 4). 473.2 × 10  m and 1.324 × 10  tons, respectively. However, The effective low-TOC carbonate source rocks are all the 3P reserves of natural gas and total oil equivalent alone 9 3 9 with type I kerogen (Fig. 7b). We use the method proposed are 594.3 × 10  m and 1.041 × 10 tons at present (Yang by Chen and Jiang (2016) to estimate the initial TOC con- 2012), more than or close to total resources of the assess- tent of effective low-TOC source rock. The TOC recovery ment. Similarly, in Tabei area, the oil, gas and oil equivalent 9 9 3 9 coefficient (TOC /TOC) ranges from 2.5 to 3.3 with an aver- resources are 1.816 × 10 tons, 820.4 × 10 m and 2.47 × 10 age of 2.9. When present-day TOC is 0.5%, the T OC can tons, respectively, while the present 3P reserve of oil has reach about 1.5%. The result is consistent with that by Pang been higher than 3.0 × 10 tons (Yang 2012), implying the et al. (2014). When source rock reaches mature stage, both presence of additional source rocks. sufficient organic matter (quantity) and good kerogen type Employing the method of hydrocarbon generation and (quality) play crucial roles in hydrocarbon generation and expulsion, quantities of hydrocarbon expulsion from the expulsion. Figure 7 also shows when TOC is less than 0.5% Middle–Upper Ordovician effective carbonate source rocks in carbonate succession, there are two types of carbonates with low-TOC in Tazhong and Tabei areas had been pre- pd for ineffective source rocks. One is that poor type of kero- liminarily estimated (Pang et al. 2018). The expelled amount gen to generate any significant amount of oil; the second is of hydrocarbons from the Middle–Upper Ordovician in that although kerogens with good types, low TOC in them Tarim Basin’s platform was estimated to be 4.09 × 10 tons could not generate sufficient hydrocarbons amount to meet oil and 13.17 × 10 tons oil equivalent, respectively. If a pro- the required threshold. portion of 10% in the expelled hydrocarbons can be trapped and accumulated in carbonate platform successions in the Table 4 Maceral compositions of kerogen in Ordovician of YW2 well Well Formation Depth (m) TOC (%) Sapropelinite group Exinite group Vitrinite-like group Inert group (%) (%) (%) (%) YW2 O y 6448.1 0.326 70 3 21 6 YW2 O y 6459.75 0.230 78 1 20 1 YW2 O y 6465.8 0.224 80 0 14 6 YW2 O y 6468.7 0.287 80 4 16 0 1 3 Petroleum Science (2020) 17:1491–1511 1509 basin, combined with the resources of Cambrian–Lower low in TOC or too poor in quality of organic matter, carbonate source rocks considered in the third round of cannot be an effective source rocks. National resource assessment, the phenomenon that the esti- mated resource potentials lower than the 3P reserves can Acknowledgements This study was financially supported by the Sci- be explained. This provides insights for the longtime con- ence Foundation of China University of Petroleum, Beijing (Grant No. troversy between geologists and geochemists regarding the 2462020BJRC005) and the Joint Funds of National Natural Science major source rocks contributing to hydrocarbon resources Foundation of China (Grant No. U19B6003-02) . We appreciate the Tarim Oilfield Company, PetroChina, especially the Research Institute in carbonate platform in the basin. This also means that the of Exploration and Development, for providing background geological effective low-TOC source rocks in Middle–Upper Ordo- pd data and permission to publish the results. We also thank the review- vician succession can also be significant for the resource ers for their constructive comments and suggestions that improved the contribution of hydrocarbon accumulations in the basin. manuscript. Open Access This article is licensed under a Creative Commons Attri- bution 4.0 International License, which permits use, sharing, adapta- tion, distribution and reproduction in any medium or format, as long 5 Conclusions as you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons licence, and indicate if changes 1. The use of present-day TOC threshold as a sole crite- were made. The images or other third party material in this article are included in the article’s Creative Commons licence, unless indicated rion for determining effective source rock is arbitrary, otherwise in a credit line to the material. If material is not included in especially for rocks with high maturity. The proposed the article’s Creative Commons licence and your intended use is not method and models in this study evaluated and com- permitted by statutory regulation or exceeds the permitted use, you will pared the hydrocarbon expulsion threshold and actual need to obtain permission directly from the copyright holder. To view a copy of this licence, visit http://creativ ecommons .or g/licenses/b y/4.0/. residual hydrocarbon amount and can be used to distin- guish effective source rocks that have expelled hydro- carbons from the non-source rocks. 2. The free hydrocarbon retained in the potential source References rock interval of the Middle–Upper Ordovician suc- Cao J, Xia LW, Wang TT, et al. An alkaline lake in the Late Paleozoic cession in YW2 Well lies between 0.034  kg/m and Ice Age (LPIA): a review and new insights into paleoenviron- 2.953  kg/m , and the calculated hydrocarbon expul- ment and petroleum geology. 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Method for identifying effective carbonate source rocks: a case study from Middle–Upper Ordovician in Tarim Basin, China

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Abstract

Hydrocarbon expulsion occurs only when pore fluid pressure due to hydrocarbon generation in source rock exceeds the force against migration in the adjacent carrier beds. Taking the Middle–Upper Ordovician carbonate source rock of Tarim Basin in China as an example, this paper proposes a method that identifies effective carbonate source rock based on the principles of mass balance. Data from the Well YW2 indicate that the Middle Ordovician Yijianfang Formation contains effective carbonate source rocks with low present-day TOC. Geological and geochemical analysis suggests that the hydrocarbons in the carbonate interval are likely self-generated and retained. Regular steranes from GC–MS analysis of oil extracts in this interval display similar features to those of the crude oil samples in Tabei area, indicating that the crude oil probably was migrated from the effective source rocks. By applying to other wells in the basin, the identified effective carbonate source rocks and non-source rock carbonates can be effectively identified and consistent with the actual exploration results, validating the method. Considering the contribution from the identified effective source rocks with low present-day TOC (TOC ) is considered, the long-standing puzzle between the proved 3P oil reserves and estimated resources in the basin pd can be reasonably explained. Keywords Effective carbonate source rock · Mass balance approach · Low present-day TOC · Ordovician · Tarim Basin 1 Introduction Edited by Jie Hao In the past, scholars in the world have put forward different definitions of effective carbonate source rock. For exam- * Jun-Qing Chen ple, Hunt (1995) regarded rocks that have generated and cjq7745@163.com expelled hydrocarbon fluid as effective source rocks. Pang * Xiong-Qi Pang et al. (1993) considered only those rocks that expel free- pangxqcup@163.com phase hydrocarbons in large quantities are effective source rocks. To be specific, only those rocks that contain sufficient State Key Laboratory of Petroleum Resources and Prospecting, China University of Petroleum, organic matter (quantity) with good kerogen type (quality) Beijing 102249, China at a certain thermal evolution stage (maturity) and that are Beijing Key Laboratory of Optical Detection Technology capable of expelling sufficient hydrocarbons for forming for Oil and Gas, China University of Petroleum, commercial accumulations, are referred as effective source Beijing 102249, China rocks. Depending on quality and maturity, the threshold of College of Geoscience, China University of Petroleum, TOC value as an effective source rock varies. In the past, Beijing 102249, China people proposed different threshold TOC values in carbon- Geological Survey of Canada, Calgary, AB T2L 2A7, ate rock, from 0.1% to 0.5%, based on different methods in Canada various basins (Table 1). For the convenience of discussion, Research Institute of Petroleum Exploration we take 0.5% as the threshold value of present-day TOC and Development, PetroChina Huabei Oilfield Company, (TOC ) to define the high organic matter and low organic pd Renqiu 062550, Hebei, China matter carbonate source rocks. For mature source rock, the China University of Geosciences, Beijing 100083, China Vol.:(0123456789) 1 3 1492 Petroleum Science (2020) 17:1491–1511 Table 1 Various threshold of TOC value as an effective carbonate source rock from different authors References Threshold of TOC value as an effective carbonate source rock Chen (1985) and Qin et al. (2004) 0.1 Ronov (1958), Liu and Shi (1994) and Huo et al. (2019) 0.2 Hunt (1967) and Tissot and Welte (1978) 0.3 Palacas (1984) and Peng et al. (2008) 0.4 Qiu et al. (1998) and Zhang et al. (2002a, 2012) 0.5 TOC denotes the residue of organic matters in the source in China as a case study to illustrate the procedure and dem- pd rocks after generation and expulsion, which does not rep- onstrate the feasibility of the proposed method. resent the initial amount TOC prior to thermal decompo- sition. Jarvie (2014) shows that depending on the type of kerogen, up to 80% of original TOC (TOC ) can be con- 2 Geological background, data verted to hydrocarbons. For example, Type I kerogen has initial hydrogen index HI > 700 mg/g (Jones 1984), which and methodology means that at least 58% TOC can be converted to hydro- carbons. Pang et al. (2014) attempted to restore the initial 2.1 Geological background TOC value by introducing a recovery factor in a study of carbonate source rocks. Based on data from six petroliferous The Tarim Basin, the largest subaerial petroliferous basin in China, has been estimated of about 20 × 10 tons oil equiva- sedimentary basins in China, the recovery coefficient (TOC / TOC ) for Type I, Type II and Type III kerogen can reach lent of hydrocarbon resources (Wang et al. 2015). In recent pd years, more discoveries have been made from the Ordovician 3.2, 2.2 and 1.5, respectively. Utilizing present-day TOC threshold as a measure for carbonate successions in Yingmaili, Halahatang, Hudson, Xinken areas in Tabei Uplift and Tazhong Uplift (Fig. 1a), determining effective source rock is rather arbitrary, incon- sistent and incomparable across source rock units, even for with the 3P reserves of 1.04 × 10 tons in Tazhong Uplift and 3.0 × 10 tons in Tabei Uplift, respectively. In contrast, an the same source rock with different thermal maturities. For example, Ronov (1958) suggested a TOC threshold of 1.4% early resource appraisal based on source rock capacity indi- cated 3.794 × 10 tons oil equivalent hydrocarbon resources for shales in the Upper Devonian Formation in the Sibe- rian platform. Organic geochemical and discoveries data only (Yang 2012), smaller than what have been already dis- covered, a long-standing puzzle in the Tarim hydrocarbon indicated that the effective source rock of Paleogene Shahe- jie Formation in Jiyang Depression, Bohaibay Basin has a exploration. Although geochemical studies suggest that hydrocarbons accumulated in the Ordovician succession are threshold of above 2% (Wang et al. 2013). Due to the fact that the adsorption and retention capacities of carbonates of geochemical signatures similar to typical hydrocarbons originated from the source rocks in Middle–Upper Ordovi- are weaker than those of clays, Tissot and Welte (1984) took 0.3% as a threshold TOC value in carbonate source rocks cian (Fig. 1b) (Zhang et al. 2000, 2002b, 2004; Wang and Xiao 2004; Zhang et al. 2007; Zhao et al. 2008; Li et al. based on empirical observations. In defining an effective source rock, the quantity, quality 2008; Wang et al. 2014), more than 200 prospecting wells penetrated the Middle–Upper Ordovician succession show and thermal maturity of kerogen are the three primary ele- ments, in addition to the characteristics of conduits imme- limited high T OC source rock beds across the basin pd (Fig. 1c). The carbon deficit in mass balance implies addi- diately in contacts with the source rock. However, the three elements compensate for each other, making a TOC thresh- tional sources, perhaps from the low-TOC source rock beds pd contributing to the discovered reserves (Huo et al. 2013; old as the sole criterion inconsistent. For example, kero- gens with better quality or higher thermal maturity could Pang et al. 2014; Liu et al. 2017). From bottom to top, the Ordovician stratigraphic lower down the threshold of initial TOC for an effective source rock because of more organic matter for conversion sequences in the Tarim Basin are the Lower Ordovician Yingshan Formation (O y), the Middle Ordovician Yiji- or lighter hydrocarbon fluid products. In this paper, we propose a method for identifying anfang Formation (O y), the Tumuxiuke Formation (O t), 2 3 the Lianglitage Formation (O l) and the Upper Ordovician effective source rock in carbonates using mass balance approaches by quantifying hydrocarbon expulsion and use Sangtamu Formation (O t) (Fig.  1b). Among the forma- tions, the Sangtamu Formation is dominated by clastic rocks, the Middle–Upper Ordovician source rock of Tarim Basin 1 3 Petroleum Science (2020) 17:1491–1511 1493 Fig. 1 The distribution of discovered hydrocarbon and Ordovician source rocks, Tarim Basin. a The distribution of discovered hydrocarbons, Tarim Basin; b strati- graphic framework of the Ordovician System in the Platform of the Tarim Basin; c The present-day measured TOC values of the Upper–Middle Ordovician source rocks (the locations of sample wells are shown in a) 1 3 Qimugen uplift Tazhong uplift Tadong uplift 400000 1200000 (b) LLS 0 200 km (a) 1 100000 Pay uplift GR Korla Lithology Example Tarim basin zone LN63 LD2 H7-2 LLD Luntai LN46 KN1 LD1 XK4 0 150 1 100000 H9001 LG39 HD23 Q2 Kongquehe slope YM2 YW2 HD17 HD13 Manjiaer depression LX1 Awati depression TD1 ZG17-1 TD2 Kashi ZG101 TZ10 Kashi depression Bachu uplift TZ45 TZ201 ZG9 TAC1 Ruoqiang M5-1 TZ79 GC4 M402 H3 TG1 HT1 Maigaiti slope Tangguzibasi depression TN1 Minbei uplift Yecheng depression Minfeng 400000 1200000 H6 Well of Typical well Well of Sample Place Boundary of Boundary of Oil Gas st nd Ordovician for method oil-source well name 1 order 2 order reservoirs reservoirs source rock verification correlation structural unit structural unit 1.0 (c) N =23 0.8 Data from experiment Data collected from oilfield 0.6 TOC= 0.5% ZG8 0.4 0.2 Limestone Mudstone Marlstone Bioclastic Micrite Sandy limestone limestone mudstone Yingjisu depression uplift Tabei Kuqa depression Ruobuzhuang uplift Minfeng depression Ruoqiang depression HD23 HD13 HD17 LN46 Q2 LD1 LD2 LG39 LN63 ZG101 ZG17-1 ZG9 TZ201 TZ79 M402 M5-1 H3 HT1 TG1 TN1 GC4 LX1 YW2 4200000 4600000 TOC,% Lower Ordovician Middle Ordovician Upper Ordovician Epoch Sang- Yingshan Yijianfang Tumuxiuke Lianglitage Formation tamu Thickness, 0~703 0~157 0~106 0~800 0~1067 m 1494 Petroleum Science (2020) 17:1491–1511 while the other formations are mainly composed of carbon- per minute until temperature reaching 650 °C. Finally, the ate rocks. temperature decreases naturally. The Yangwu 2 (YW2) well, located to the west of The GC–MS analysis results for the interval from the Yangwu 2 (YW2) structure in the Manbei structural zone YW2 well (4 samples) and those of discovered oils in the in the north of Manjiaer depression, Tarim Basin (Fig. 1a), Yingmaili (3 samples) and Halahatang oilfields (3 sam- has been studied to investigate the generation potential of ples) in the Tabei area are collected from the Tarim Oilfield the Middle–Upper Ordovician source rocks in recent years Company, PetroChina. The sample locations are shown in (Zhu et al. 2011). This well is also chosen as a case in this Fig. 1a. Other data, including reservoir volumetric param- study because of two reasons, (a) continuous sampling of eters, oil density, water salinity, formation pressure and every meter for entire interval of interested; and (b) deep- temperature and others, are also collected from the com- est penetration reaching the Middle Ordovician carbonate. pany in the study. Eighty six samples were taken from the entire Ordovician interval penetrated from 6411 m to 6496 m (vitrinite reflec-2.3 Principle and methodology tance equivalent from 1.3% to 1.4%), and among them, fluo- rescence, oil stain and oil shows can be found easily. Pang et al. (1993, 2005) and Pang (1995) discussed the con- cept of hydrocarbon expulsion threshold based on mass bal- ance theory which mean the sum of hydrocarbon generation, 2.2 Experiments and data reservation and expulsion keeps constant in a source rock system. The expulsion threshold is defined as a quantity of QA/QC were preliminarily conducted on samples to ensure hydrocarbon generated in a source rock system, at which the the representativeness and free of contaminations from arti- induced over-pressure caused by fluid expansion exceeds facts. During sample preparation, the samples were cleaned capillary force and causes massive hydrocarbon migration first with distilled water in order to dispel any annexing out of the source rock into carrier beds under a new hydro- agents from drilling mud. The samples were crushed to 80 dynamic equilibrium (Pang et al. 1993, 2005; Pang 1995) mesh after drying for 5 h at 55 °C and then sealed in glass (Fig. 2). Thus, an effective source rock is defined the one bottles for further examinations. that has expelled large quantity of hydrocarbon fluids and Two laboratory experiments are conducted in this study: the expulsion threshold is used to identify effective source TOC content analysis and Rock–Eval pyrolysis. In order to rock. The expulsion threshold can be described by geologi- guarantee experimental quality, a finely GBW(E)070037a cal conditions such as depth (H), organic type, thermal matu- sample in powder form with TOC of 2%, S of 8.2 ± 0.3 mg/g rity (R ) and organic abundance (TOC), critical saturation 2 o and T of 439 ± 2 °C was selected as the standard. To keep of expulsion (S ). All definitions of the variables mentioned max o the consistency, the standard sample was analyzed both at in this study are introduced in the Table 2. commence and end of each batch of samples as well as In the Middle–Upper Ordovician case study of the Tarim between every five samples within each batch. Basin, the determination of effective source rock is based In the TOC analysis, each sample was taken weighted on the balance between quantity of hydrocarbon generated 100 mg and the CS-230HC machine produced by LECO and quantity of hydrocarbon required by primary migration Company of USA was utilized. Dilute hydrochloric acid was (Pang et al. 1993, 2005; Pang 1995). If the quantity of hydro- dripped onto the samples to get rid of inorganic carbons until carbon generated is reached or greater than the expulsion no bubbles were formed. And then distilled water was used threshold, the source rock is regarded as effective that con- to rinse simples multiple times for neutralizing hydrochloric tributed to hydrocarbon accumulation in the region. In this acid in the samples. Finally, those samples were exsiccated paper, the expulsion threshold is estimated from a statistical at a low temperature around 40  °C and incinerated with model that was established on large number of observations oxygen at a high temperature for the conversion of TOC in well-studied petroleum-bearing sedimentary basins in content to CO . Infrared detector was used to measure the China (Pang et al. 2005). The hydrocarbon expulsion thresh- S experimental signal. old is determined where the hydrocarbon generation poten- In order to conduct Rock–Eval pyrolysis experiment, tial in Fig. 2, the envelope curve of data points of ((S + S )/ 1 2 the amount of free S and pyrolyzed hydrocarbons and the TOC) × 100, reaches its maximum value (Pang et al. 2005). highest pyrolysis temperature (T ) can be acquired by When source rocks are buried deeper than the hydrocarbon max Rock–Eval 6 instrument. The beginning temperature of expulsion threshold, hydrocarbons are expelled from source pyrolysis procedure was set to be 300 °C and held for 3 min. rocks, and the hydrocarbon generation potential decreases Further, the increasing rate of temperature was set at 25 °C (Chen et al. 2020). 1 3 Petroleum Science (2020) 17:1491–1511 1495 3 3 3 Hydrocarbon amount per volume of rock (Q, kg/m or m /m ) m , is quantity of liquid residual hydrocarbon in a single unit volume of rock at expulsion threshold; Q , kg/m , is rag quantity of absorbed gas in a single unit volume; Q , kg/ rwg m , is quantity of water-soluble gas in a single unit volume; and Q , kg/m , is quantity of oil-soluble gas in a single unit rog volume. All the quantities are measured at the expulsion Residual hydrocarbon Q < Q r rm threshold in source rock. curve (1) Calculation of liquid hydrocarbons (Q ) at expulsion ro 2000 threshold Pang et al. (1993) analyzed the liquid residual hydrocarbons Hydrocarbon expulsion Q = Q r rm in source rocks and their relationship with major geologi- threshold Qrag cal controlling factors based on the real data from Songliao 3000 rwg Qrog Basin, Hailaer Basin and Tarim Basin in China and estab- ro lished a statistical model for estimating the quantity of liq- uid residual hydrocarbons at the expulsion threshold in the source rock. The model has the following form: Q ≥ Q r rm Hydrocarbon generation Q =  ⋅ ( +Δ) ⋅ S (2) ro o n om curve � 2 − (R −R ) ∕D n o S = f (C%) ⋅ e ∕(1 − B ) (3) om k Qrm Q f (C) = A + A ⋅ C + A ⋅ (C) (4) 0 1 2 Residual Residual water Residual oil absorbed gas soluble gas soluble gas Expelled 2 Residual oil B = 0.81 − 1.05R + 0.18(R ) (5) hydrocarbon k o o where φ , %, is porosity in normal compaction state; Δφ Fig. 2 Mass balance model of hydrocarbon generation, residue, is residual porosity in under compacted state; S , %, is expulsion variation of source rock (modified from Pang et al. 1993). om Before hydrocarbon expulsion threshold, all of the hydrocarbons are saturation of liquid residual hydrocarbon in source rock. retained in source rock since the fluids are not enough to be able to f(C) is correlation factor of organic matter abundance and migrate against capillary sealing; at the hydrocarbon expulsion liquid residual hydrocarbon amount in source rock; B , %, threshold, fluids in source rock are sufficient to trigger the secondary represents the proportion of light hydrocarbons in liquid migration and the expulsion amount is zero; after the hydrocarbon expulsion threshold, source rock expels movable hydrocarbons, and hydrocarbons; C, %, represents organic matter content; R , expulsion amount would increase with growing maturity and might %, represents vitrinite reflectance; ρ , kg/m , is density of gradually decrease when exhausting its ability to generate hydrocar- liquid residual hydrocarbons; A , A , A , D and R’ are unde- o 1 2 bons either through lack of sufficient organic matter or due to reach- termined constants concerning the characteristics of the ing an over mature state source rocks in the study area. (2) Calculation of absorbed gas at expulsion threshold (Q ) rag 2.4 Model for calculating hydrocarbon expulsion The absorbed gas at expulsion threshold can be estimated threshold using the following expression: According to the previous study (Pang et al. 1993, 2005; Pang 1995; Jiang et al. 2002, 2006), residual hydrocarbons Q = Q ⋅  (6) rag rai g in source rocks mainly include liquids, free and adsorbed i=1 gases, water-soluble and oil-soluble gases (Fig. 2, Eq. 1): 3 3 where Q, m /m , is quantity of residual absorbed hydrocar- rai Q = Q + Q + Q + Q bon component i in a signal unit volume of rock; i represents rm ro rag rwg rog (1) th the i component of gaseous hydrocarbons, such as CH , where Q , kg/m , is quantity of hydrocarbon in a single rm C H, C H ; ρ , kg/m , is density of gaseous hydrocarbons. 2 6 3 8 g unit volume of source rock at expulsion threshold; Q , kg/ ro 1 3 Paleo depth of source rock during evolution (H, m) 1496 Petroleum Science (2020) 17:1491–1511 The amount of absorbed gas is mainly related to source Q = Q ⋅ (13) rock properties (organic matter abundance, organic matter rwg rwgi g i=1 type, organic matter maturity, mineral components and specific surface areas), formation pressure and temperature, gaseous hydrocarbon components and concentration and other factors Q = q (i) ⋅  ⋅ 1 − S (14) rwgi w o (Dubinin 1960; Schettler et al. 1991; Robert and Zoback 2014; 3 3 where Q, m /m , is water-soluble hydrocarbon compo- Ross and Bustin 2009). Pang et al. (1993) analyzed the influ- rwgi nent i in pore water; i represents different components of ence of each of the factors in a relation to the absorbed hydro- gaseous hydrocarbons such as CH , C H, C H ; ρ , kg/m , carbon component i based on the data collected from Songliao 4 2 6 3 8 g 3 3 is density of gaseous hydrocarbons; q (i), m /m , is solu- Basin, Hailaer Basin and Tarim Basin in China. An empirical w ble gaseous hydrocarbon component i amount in formation model was established to simulate the amount of absorbed water; φ, %, is source rock porosity; S , %, is fluid residual gas component i amount. The model can be expressed quan- o hydrocarbon flow saturation in source rock. titatively in the following equations (Pang et al. 1993; Tian In their study, an empirical model was also established et al. 2010): to estimate gas component i amount in formation water, −n(T−20) Q = K ⋅  ⋅ K(C%) ⋅ K R ∕K ⋅ a ⋅ b ⋅ P ⋅ e ∕(1 + b ⋅ P) rai i r o w i i i which is displayed as follows (Pang et al. 1993; Tian et al. (7) 2010). n = 0.02∕(0.993 + 0.0017P) (8) q (i)= q (1, T, P, X ) ⋅ q (i, T, P)∕q (1, T, P) (15) w w K w w K R = 0.836 + 0.68 R + 0.498 R 1.33 (9) o o o q 1, T, P, X = 1.15 ⋅ 0.005 ⋅ T ⋅ 22.4∕16 w K ⋅ 0.994 − 0.0032 ⋅ X + 0.0007 ⋅ T K(C) = B + B ⋅ C (10) 0 1 (16) 2 2 1−P q (i, T, P) = a + a ⋅ P + a ⋅ T + a ⋅ P + a ⋅ T + a ⋅ P ⋅ T w 0i 1i 2i 3i 4i 5i K = 1 + 0.445e (11) (17) ⎧ ⎧ ⎧ 0.079 0.117 5.32 CH a = 2.416 a = 1.229 a = 0.231 ⎧ ⎧ ⎧ ⎧ 4 01 02 03 ⎪ ⎪ ⎪ ⎪ ⎪ ⎪ ⎪ 0.00478 0.723 0.15P + 0.30 C H a = 0.00961 a = 0.00137 a = 0 2 6 ⎪ 11 ⎪ 12 ⎪ 13 K = a = b = i = ⎨ ⎨ ⎨ ⎨ i i i 0.0066 1.309 3.04P + 0.6858 C H ⎪ ⎪ ⎪ a =−0.0348 a =−0.0175 a = 0 3 8 21 22 23 ⎪ ⎪ ⎪ ⎪ ⎨ ⎨ ⎨ −5 −6 −6 ⎩ 0.0038 ⎩ 1.833 ⎩ 8.688P + 1.065 ⎩ C H a =−1.04 × 10 a =−3.87 × 10 a =−3.31 × 10 4 10 31 32 33 ⎪ ⎪ ⎪ −7 −7 −7 (12) a = 9.05 × 10 a = 3.94 × 10 a = 4.26 × 10 ⎪ ⎪ ⎪ 41 42 43 −5 −5 −5 ⎪ ⎪ ⎪ a = 6.14 × 10 a = 3.27 × 10 a = 1.141 × 10 51 52 53 where n means correlation factor related to pressure, as an ⎩ ⎩ ⎩ (18) integer; T, °C, represents formation temperature; P, Pa, is 3 3 formation pressure; C, %, refers to organic matter content; where q (i), m /m , is soluble gaseous hydrocarbon com- R , %, means vitrinite reflection; K is wettability, dimen- o w ponent i amount in formation water; T, °C, represents the sionless; K(C) is correlation factor between organic matter formation temperature; P, MPa, is the formation pressure; abundance and absorbed gas amount in source rock; K(R ) o X , g/L, means salinity of formation water; q (1, T, P, X ) K w K is correlation factor between thermal maturity and absorbed is variance of methane solubility in water controlled by pres- gas amount in source rock; K is correlation factor between i sure, temperature and water salinity; q (1, T, P) is solubil- hydrocarbon component and absorbed gas amount in source ity of gaseous hydrocarbon component i in pore water con- th rock; i represents the i component of gaseous hydrocarbons trolled by pressure, temperature and water salinity. such as CH , C H, C H and C H ; ρ , kg/m , is density of 4 2 6 3 8 4 10 r source rocks; and B and B are related coefficients for the 0 1 (4) Calculation for oil-soluble hydrocarbon (Q ) at expul- rog relationship between absorbtion ability of source rocks and sion threshold organic carbon content. The calculation model of oil-soluble gas amount can be (3) Calculation of water-soluble gas (Q ) at expulsion rwg expressed as follows: threshold. Q = Q ⋅  (19) rog rogi g The calculation model of water-soluble gas can be i=1 expressed as follows: 1 3 Petroleum Science (2020) 17:1491–1511 1497 solvent, the unit being a proportion of the weight of extrac- Q = q (i) ⋅  ⋅ S rogi o o (20) tion to that of rock. ‘S ’ is measured hydrocarbons from 3 3 where Q, m /m , is quantity of oil-soluble hydrocarbons Rock–Eval pyrolysis when the rock is heated at 300 °C. rogi component i in pore oil; i represents component of gaseous However, these two approaches for measuring actual resid- 3 3 3 hydrocarbons such as CH , C H, C H , kg/m ; q (i), m /m , ual hydrocarbon amount are not perfect. During the sam- 4 2 6 3 8 o is quantity of gaseous hydrocarbons component i dissolved pling and sample preparation, gaseous residual hydrocar- in liquid hydrocarbons; φ, %, is source rock porosity; S , %, bons are inevitably easily lost on the surface (Jiang et al. is fluid residual hydrocarbon flow saturation in source rock. 2016). Therefore, gaseous hydrocarbons amount in rock is Previous study shows that pore pressure and formation mostly not included in the parameters ‘A’ or ‘S ’. Further- temperature are the two major geological factors controlling more, change in temperature and pressure causes certain the amount of residual oil-soluble gaseous hydrocarbons. light liquid hydrocarbons to be released, especially those Based on the findings, Pang et al.(1993) built a correspond- with carbon atoms fewer than 15. In conclusion, residual ing model to simulate residual gas constituent i amount in oil hydrocarbons contained in ‘S ’ and ‘A’ are only a portion per volume of rock based on the experiments and study that of actual residual hydrocarbons in rocks. The components is displayed as follows (Pang et al. 1993; Tian et al. 2010). and loss amount vary with different lithologies. The maxi- mum hydrocarbon evaporative loss rate can be up to 80% q (i)= 4.95 ⋅ K(i) ⋅ K( ) ⋅ q (T, P) o o og (21) (R ≤ 1.3%) by Chen et al. (2018) of Type I kerogen. The study result is consistent with that by Xue et al. (2016) of K(i) = (A(i) + B(i) ⋅ P)∕100 76% loss rate through kinetic study of hydrocarbon genera- (22) tion. When R > 1.3%, the hydrocarbon evaporative loss rate would increase with increasing R as more oil crack to gas- K  = 1.75 − 1.8 ⋅ (23) o o eous and light hydrocarbons that are more susceptible to evaporative loss. In addition, compared to ‘A’, ‘S ’ contains q (T, P)=−0.726 + 0.387 ⋅ P − 0.0323 ⋅ T og (24) more scarce residual hydrocarbons, as a consequence of ‘S ’, representing only the hydrocarbons released before heating A(1) = 62.63 B(1) = 0.00716 at 300 °C, while constituents with larger molecular weight ⎧ ⎧ ⎪ ⎪ or high polarity remain in the rocks. Therefore, light hydro- A(2) = 18.68 B(2) = 0.00365 (25) ⎨ ⎨ A(3) = 9.89 B(3) = 0.00212 carbon compensation calibration is necessary to offset these ⎪ ⎪ ⎩ ⎩ losses when calculating actual residual hydrocarbon amount A(4) = 4.203 B(4) = 0.00085 using ‘A’ and ‘S ’. 3 3 where q (i), m /m , is quantity of gaseous hydrocarbons The actual residual hydrocarbons amount (Q ) was calcu- component i dissolved in liquid hydrocarbons in a signal lated according to ‘S ’ in this study based on the Rock–Eval 3 3 unit volume; q (T, P), m /m , is the gaseous hydrocarbon og pyrolysis results of representative samples chosen. The light in liquid hydrocarbons, an empirical function of temperature hydrocarbons component was compensated in ‘S ’ accord- and pressure conditions; K(i) is proportion of component i ing to Pang et al. (1993), and the amount of actual residual of gaseous hydrocarbons dissolved in liquid hydrocarbons, hydrocarbons was calculated, utilizing the calibrated resid- decimal; K(ρ ) is calibration factor reflecting variation of ual amount (S ) according to the equations displayed as 1+ oil-soluble gaseous hydrocarbons with oil density, as an follows: integer; ρ , kg/m , is density of gaseous hydrocarbons; T, S = S ∕(1 − B ) °C, represents the formation temperature; and P, Mpa, rep- (26) 1+ 1 k resents the formation pressure. Q = S ⋅ (27) r 1+ r 2.5 Model for calculating actual residual where S , mg/g, is actual residual liquid hydrocarbon 1+ hydrocarbon amount amount considering light hydrocarbons; S , mg/g, is the free hydrocarbon amount acquired through pyrolysis experi- Generally, chloroform bitumen ‘A’ and ‘S ’ obtained through ments; B , %, refers to percent by weight of light hydrocar- extraction and pyrolysis experiments were used to represent bons in entire liquid hydrocarbon; as shown in Eq. 5; ρ , kg/ actual residual hydrocarbon amount. Chloroform ‘A’ refers m , is the density of source rocks. to residual hydrocarbons extracted by chloroform organic 1 3 1498 Petroleum Science (2020) 17:1491–1511 source rock density, formation temperature, formation pres- 3 Results sure, oil saturation and formation water salinity. 3.1 Parameters for study area (1) Crude oil density There are some essential geological parameters data for the Increase in depth leads to a rise in formation temperature, simulation of theoretical residual hydrocarbon amount at which leads to a decreasing trend of crude oil density (Fig. 3a). expulsion threshold and calculation of actual residual hydro- The relationship between oil density and depth can be fitted as carbon amount, including crude oil density, porosity, total follows, according to 893 measured crude oil density data from organic carbon, vitrinite reflectance, natural gas density, carbonate reservoirs in Tarim Basin’s platform: Density, g/cm TOC, % VR , % (a) (b) (c) (d) 00.5 1.01.5 00.5 1.01.5 00.5 1.01.5 Porosity (%) 0 6400 5,500 05 10 15 20 N=785 5,600 N = 893 N = 86, N = 14, YW2 well LN46 well logging porosity 5,700 P50 5,800 4000 6460 5,900 6480 y = 805.36ln(x) + 5955.1 R = 0.7427 6,000 7000 6,100 8000 6520 6,200 Formation water Pressure, MPa Temperature, °C Oil sauration,% salinity, g/L (e) (f) (g) (h) 020406080 050 100 150 200 0306090 120 0 100 200 300 0 0 0 0 Formation pressure 1000 1000 1000 1000 N = 324 N = 134 N = 122 N = 495 2000 2000 2000 2000 y = 68.57x + 928.32 3000 3000 R = 0.7792 3000 3000 4000 4000 4000 4000 5000 5000 5000 5000 6000 6000 y = 50.647x - 1479.5 6000 6000 7000 7000 R = 0.7435 Hydrostatic pressure 7000 8000 7000 8000 1.0 (i) (j) Confirmed source rock Confirmed source rock 0.8 N = 56 N = 13 y = 0.024x - 0.057x + 0.026 2 5 R = 0.684 0.6 y = 0.7304x + 0.3244 R = 0.8147 0.4 0.2 0 0 012345 6 0246 81012 TOC, % TOC, % Fig. 3 Parameters of carbonate rocks in the platform of Tarim Basin. a Relationship between oil density and depth; b relationship between porosity and depth; c relationship between TOC and depth of YW2 well; d relationship between VRE and depth of carbonate rocks in LN46 well; e relationship between pressure and depth; f relationship between temperature and depth; g relationship between oil saturation and depth; h relationship between formation water salinity and depth; i relationship between “A” and TOC of confirmed typical source rock; j relationship between gas absorption amount and TOC of confirmed typical source rock (absorption experiment data) 1 3 Depth, m Depth, m Chloroform asphalt “A”, % Depth, m Depth(m) Depth, m Depth, m Absorption amount gas, m /t Depth, m Depth, m Petroleum Science (2020) 17:1491–1511 1499 −6 feature (Fig. 3e). The relationship between formation pres- =−7.7 ∗ 10 H + 0.88 (28) sure and depth in Tarim Basin’s platform is obtained based where ρ , g/cm , is crude oil density; and H, m, refers to on 324 measured formation pressure data with different depth. depths, which is displayed as follows. P = 0.011H − 0.416 (32) (2) Porosity where P, MPa, is pressure, and H, m, refers to depth. Along with increasing depth, the porosity of carbonate rocks in Tarim Basin’s platform present two relative large (6) Temperature areas, in which the porosity values gradually increase to a maximum due to karstification under unconformity sur - In general, temperature increases linearly with depth faces (Lin et al. 2012) and carbonate rock dissolution by (Fig. 3f). The formation temperature of Tarim Basin’s plat- acidoid since hydrocarbon was generated and expelled form can be calculated according to 134 actual tempera- (Surdam et al. 1984; Eseme et al. 2012) then decreases to ture data with different depth. The relationship between a normal matrix porosity (Fig. 3b). The relationship can be temperature and depth is displayed below: obtained by 785 logging porosity data of local dry layers T = 0.014H + 52.31 (33) with different depth in Tarim Basin’s platform, and it can be fitted as per the two binomials: where T, °C, is temperature; and H, m, refers to depth. −6 2 −2 𝜑 = 2.2 × 10 H + 1.7 × 10 H − 28.63,H < 5100 (29) (7) Oil saturation −6 2 −2 = 3.1 × 10 H + 3.6 × 10 H − 101.35,H ≥ 5100 (30) As shown in Fig.  3g, with increasing depth porosity decreases and oil saturation increases. According to 122 where φ, %, is formation porosity; and H, m, refers to depth. measured data with different depth, the relationship was determined in Tarim Basin’s platform as below: (3) TOC S = 0.5608 ⋅ ln(H)− 4.074 (34) The total organic carbon (TOC) data of source rocks where S , %, is oil saturation; and H, m, refers to depth. were obtained from 86 measured data by the experiment designed during the study (Fig.  3c); the location and (8) Formation water salinity experimental methods are shown in Sect. 2.1. It can be easily seen that formation water salinity (4) Vitrinite equivalent increases with depth in Tarim Basin’s platform (Fig. 3h). Due to lack of data on source rock water salinity, that of There is an obvious relationship between vitrinite equivalent reservoir rocks could be used, while carbonate rock is (VR ) and depth of marine source rocks in Tarim Basin plat- both source rock and reservoir. The following equation form, wherein VR appears to exponentially increase with describes the relationship between formation water salin- depth (Fig. 3d). Due to lack of measured values for vitrinite ity and depth, based on 494 measured formation water equivalent of YW2 well, that of LN46 well was used, since salinity data: which is located in the Tabei Uplift and displays the same tectonic setting as YW2 well. The relationship between VR 0.0003H X = 25.563e (35) and depth is well fitted by using 14 practically measured vitrinite equivalent data from LN46 well in the Tabei Uplift, where X , g/L, is formation water salinity, and H, m, refers which can be expressed as: to depth. 0.00092H VR = 0.00405e (31) (9) Other parameters and coefficients where VR , %, is vitrinite equivalent, and H, m, refers to Other parameters used for calculations were adopted from depth. empirical data of Tarim oilfield. For example, natural gas density is taken at an average of 0.71 kg/m ; bulk rock den- (5) Pressure sity 2.6 g/cm is adopted as carbonate source rock density value; normal temperature in the study area is considered The carbonate Cambrian and Ordovician Systems in Tarim as 20 °C. Basin show a normal pressure and a little overpressure 1 3 1500 Petroleum Science (2020) 17:1491–1511 As mentioned above, there are many characteristics in The source rock properties (organic matter abundance, source rock, including source rock lithology, mineral con- organic matter type, organic matter maturity, mineral com- stituent, specific surface area and TOC which is only one ponents and specific surface areas) also control the amount of the factors that control residual oil hydrocarbon amount of absorbed gas (Dubinin 1960). Parameter K(C) is set to (Tissot and Welte 1984). In order to serviceably describe the describe the absorbtion ability of source rocks with differ - retention characteristics of source rocks in the study area, ent organic carbon abundances, and B and B are related 0 1 f(C) is set to characterize the residual capacity of source coefficients for the linear relationship between absorbtion rocks with different TOC, and A , A and A are empiri- ability of source rocks and TOC in the study area. A total of 0 1 2 cal constants in study areas related to f(C). They are calcu- 14 data from typical source rocks interval were selected to lated by simulation and statistical analysis of actual residual determine B and B . The typical source rock interval was 0 1 hydrocarbon amount in source rocks. A total of 56 data from the one confirmed that a large amount of hydrocarbon expul- typical source rocks interval were selected to calculate and sion have occurred. The data were from adsorption experi- determine A , A and A in the study area. The typical source mental results by the Tarim Oilfield Company, PetroChina. 0 1 2 rock data were confirmed that massive hydrocarbon expul- According to the relationship, B = 0.324 and B = 0.730 can 0 1 sion has occurred (Li et al. 2015). The 56 data are from be obtained (Fig. 3j), respectively. PetroChina Tarim Oilfield Company. According to the bino- mial (Fig. 3i), A = 0.026, A = −  0.057, A = 0.024 can be 3.2 Calculation results of hydrocarbon amount 0 1 2 determined for Eq. (4). D refers to variance of the 56 TOC at expulsion threshold data, and D = 0.0163 is determined for Eq. (3). R’ is the gen- eral hydrocarbon expulsion threshold of the source rocks in All parameters and coefficients obtained above were substi- Tarim Basin, and R′= 0.95% is determined for Eq. (3) (Pang tuted in each calculation model, through which the hydro- et al. 2012). carbon amount at expulsion threshold was determined for 3 3 3 3 3 Q , kg/m Q , m /m Q , m /m ro rag rwg (a) (b) (c) 0.095 0.100 0.105 0.110 0.352 0.353 0.354 0.355 0.356 0.357 0.0019 0.00195 0.00200 0.002050.0021 0.090 6400 6400 6400 N =86, YW2 well N =86, YW2well N =86, YW2well 6410 6410 6410 6420 6420 6420 6430 6430 6430 6440 6440 6440 6450 6450 6450 6460 6460 6460 y =32104x - 4896 R =0.7763 6470 6470 6470 y = -6953.22x + 7148.73 y = -567561.24x +7591.46 6480 6480 6480 2 2 R =1.00 R = 0.99 6490 6490 6490 6500 6500 6500 Qro Qrag Qrwg 6510 6510 6510 3 3 3 3 Q , m /m Q , kg/m Q , kg/m rog rg rm (d) (e) (f) 0.075 0.080 0.085 0.090 0.306 0.308 0.310 0.312 0.314 0.4000.405 0.4100.415 0.420 6400 6400 6400 N =86, YW2 well N =86, YW2well N =86, YW2well 6410 6410 6410 6420 6420 6420 6430 6430 6430 6440 6440 6440 6450 6450 6460 6460 6460 y = -4390.58x +8251.56 R = 0.70 6470 6470 6470 y = -9255.07x + 7197.82 R = 0.99 y = -16591x +11589 6480 6480 6480 R =0.9982 6490 6490 6490 6500 6500 6500 Qrog Qrg Qrm 6510 6510 6510 Fig. 4 Relationship of residual hydrocarbon amount and depth of YW2 well, Tarim Basin. a Liquid hydrocarbon amount; b absorbed gas amount; c water-soluble gas amount; d oil-soluble hydrocarbon amount; e gaseous hydrocarbon amount; f total hydrocarbon amount 1 3 Depth, m Depth, m Depth, m Depth, m Depth, m Depth, m Petroleum Science (2020) 17:1491–1511 1501 the case study of YW2 well. Results indicate that hydro- carbonate source rocks (Liu et al. 2017). This is consistent carbon amounts at expulsion threshold of liquid, and gas with the study results by Peters and Moldowan (1993) on soluble in oil and water, decrease linearly with increasing the oil characteristics from marine carbonate source rocks. depths (Fig. 4a, c, d), while gas adsorption in rocks increases Compared with mudstone, the threshold of TOC value with depth (Fig. 4b). However, in general, the total gaseous as an effective source rock of carbonate rock is generally hydrocarbons and the total hydrocarbons at expulsion thresh- smaller. On the one hand, the adsorption and retention old decrease linearly with increasing burial depth (Fig. 4e, capacities of carbonates are weaker than clays (Tissot and f). The hydrocarbon amount at expulsion threshold based on Welte 1984), resulting in a less minimum generation amount modeled parameter values and actual TOC data varies from to expel hydrocarbons. Pyrolysis experiments also clearly 3 3 0.402 kg/m to 0.418 kg/m , with a mean value of 0.410 kg/ manifested that clay-rich rocks can retain a significantly 3 3 m , among which the absorbed gas amounts from 0.352 m / greater quantity of hydrocarbons than carbonate source 3 3 3 m to 0.356  m /m , the water-soluble gas amounts from rocks (Katz 1983). On the other hand, different from marl 3 3 3 3 0.0019 m /m to 0.0021 m /m , the oil-soluble gas amounts source rocks, bioprecursors of carbonate source rocks are 3 3 3 3 from 0.076 m /m to 0.082 m /m , and the oil amounts from mainly plankton assemblages (Liu et al. 2017) with high 3 3 3 0.064 kg /m to 0.106 kg/m (Table 3). hydrocarbon transformation ratio, resulting in low present- day TOC values remaining in the source rocks. Type I and 3.3 Calculation results of actual residual Type II kerogens (regardless of the weight of TOC, their hydrocarbon amount hydrocarbon yield are significantly higher) are, in general, more easily found in carbonates than in siliciclastic facies Actual residual hydrocarbon amount in Middle–Upper Ordo- (Hunt 1967). Additionally, different from mudstones, the vician source rocks in YW2 well can be estimated by using mineral constituent of carbonate source rocks has specialty these parameters and Rock–Eval pyrolysis data (S ) (Fig. 5), that during geological process, hydrocarbons, aqueous car- 3 3 and the amount lies between 0.034 kg/m and 2.953 kg/m boxylic acids and carbon dioxide produced by hydrolytic (Table 3). disproportionation may reach a state of invertible metastable thermos dynamic equilibrium, including sedimentary min- 3.4 Identification results of effective source rocks erals such as calcite (Helgeson et al. 1993; Jeffrey 2003), forming carboxylate salts with the structure compatible Based on the above method and calculation results, it can in carbonate minerals and then preserved in the carbonate be determined whether hydrocarbon expulsion has occurred source rocks. These carboxylate salts widely distributed in in Middle–Upper Ordovician interval of YW2 well. Results marine carbonate source rocks, keep stable in low tempera- indicate that hydrocarbon expulsion took place in carbon- ture and have certain hydrocarbon generation capability at ate source rocks which have a low value of T OC in the high evolution stage (Carothers and Kharaka 1978; Vande- pd Yijianfang formation between 6452 m and 6487 m (Fig. 6). grift and Horwitz 1980; Liu et al. 2017). Since during our traditional TOC values tests inorganic carbon contents are removed by dripping diluted hydrochloric acid, the organic 4 Discussion carbon contents of carboxylate salts would be easy to lose leading to the underestimate of TOC values and hydrocarbon Early in 1933, Trask pointed out the hydrocarbon genera- generation potential at high evolution stage (Liu et al. 2016). tion capacity of carbonate rocks. In the following decades, However, the loss of organic carbon affects more lightly to people gradually began to pay attention to carbonate rock the TOC test of muddy source rocks, since the contents of series and carried out a series of targeted research work. acid-soluble carbonate minerals of them are low and the The studies effectively guided oil and gas exploration, and a partial acidic environment where muddy source rock formed number of large and medium oil and gas fields contributed is not beneficial for the formulation of carboxylate salts (Liu by carbonate source rocks were successfully discovered. et al. 2017). For example, the Paleozoic strata in the Williston Basin are almost composed of limestone, dolomite and evaporate, with 4.1 Hydrocarbons self‑generated and retained very few argillaceous rocks. Its oil and gas mainly come in samples from the Red River, Winnipegosis, Bakken and Lodgepole Formation of the Upper Ordovician–Lower Carboniferous Due to the particularity of lithology, carbonate rocks can (Tao et al. 2013). The organic geochemical indexes of oils act as source rocks to provide hydrocarbons as well as res- in the Tahe Oilfield in the Tarim Basin show the ratio of C ervoir rocks to provide storage for hydrocarbon accumula- hopane/C hopane over 0.6 and C S hopane/C S hopane tion (Trask 1933; Li et al. 1998; Wang et al. 2016; Liu et al. 30 35 34 over 0.8, indicating obvious characteristics of derived from 2017). Therefore, it is essential to ensure the hydrocarbons 1 3 1502 Petroleum Science (2020) 17:1491–1511 Table 2 Summary table of definitions of the variables Variable Definition Unit Q The actual residual hydrocarbons amount kg/m Q The quantity of hydrocarbon in a single unit volume of source rock at expulsion threshold kg/m rm Q The quantity of liquid residual hydrocarbon in a single unit volume of rock at expulsion threshold kg/m ro Q The quantity of absorbed gas in a single unit volume kg/m rag Q The quantity of water-soluble gas in a single unit volume kg/m rwg Q The quantity of oil-soluble gas in a single unit volume kg/m rog 3 3 Q The quantity of residual absorbed hydrocarbon component i in a signal unit volume of rock m /m rai 3 3 Q Water-soluble hydrocarbon component i in pore water m /m rwgi 3 3 Q The quantity of oil-soluble hydrocarbons component i in pore oil m /m rogi i The ith component of gaseous hydrocarbons such as CH , C H, C H and C H 4 2 6 3 8 4 10 φ Source rock porosity % φ Porosity in normal compaction state % Δφ Residual porosity in under compacted state % S Fluid residual hydrocarbon flow saturation in source rock % S Saturation of liquid residual hydrocarbon in source rock % om f(C) Correlation factor of organic matter abundance and liquid residual hydrocarbon amount in source rock B The proportion of light hydrocarbons in liquid hydrocarbons % C Organic matter content % R Vitrinite reflectance % ρ Density of liquid residual hydrocarbons kg/m ρ Density of source rocks kg/m ρ Density of gaseous hydrocarbons kg/m A , A , A , D and R′ Constants concerning the characteristics of the source rocks in the study area 0 1 2 n Correlation factor related to pressure T Formation temperature °C P Formation pressure Pa or MPa K Wettability K(C) Correlation factor between organic matter abundance and absorbed gas amount in source rock K(R ) Correlation factor between thermal maturity and absorbed gas amount in source rock K(i) Proportion of component i of gaseous hydrocarbons dissolved in liquid hydrocarbons K(ρ ) Calibration factor reflecting variation of oil-soluble gaseous hydrocarbons with oil density, as an integer K Correlation factor between hydrocarbon component and absorbed gas amount in source rock B B Related coefficient for the relationship between absorbtion ability of source rocks and organic carbon 0 1 content X Salinity of formation water g/L 3 3 q (i) Soluble gaseous hydrocarbon component i amount in formation water m /m q (1, T, P) Solubility of gaseous hydrocarbon component i in pore water controlled by pressure, temperature and water salinity q (1, T, P, X ) Variance of methane solubility in water controlled by pressure, temperature and water salinity w K 3 3 q (i) Quantity of gaseous hydrocarbons component i dissolved in liquid hydrocarbons m /m 3 3 q (T, P) The gaseous hydrocarbon in liquid hydrocarbons, an empirical function of temperature and pressure condi- m /m og tions S Actual residual liquid hydrocarbon amount considering light hydrocarbons mg/g 1+ S Free volatile hydrocarbons thermally flushed from a rock sample at 300 °C mg/g S Products that crack during standard Rock–Eval pyrolysis temperatures (300–650 °C) mg HC/g rock H Depth m T The highest pyrolysis temperature °C max TOC Total organic carbon wt% TOC Initial TOC content wt% TOC Present-day TOC wt% pd 1 3 Petroleum Science (2020) 17:1491–1511 1503 Table 2 (continued) Variable Definition Unit VR Vitrinite equivalent % (a) S , mg/g 00.2 0.40.6 0.81.0 N =86, YW2 well (b) Sample temperature, °C 102389 645159 434 708 840 Oxidation FID signal Sample temperature IR CO signal IR CO signal 0 371 0102030405060 70 Time, min Well Sample Depth, mWeight, mg S1, mg/g S2, mg/g TOC, % Tmax, °C YW2C-625221 6454 71.0 0.58 0.52 0.275 462 (c) Sample temperature, °C 103383 644159 434 707 840 Oxidation FID signal Sample temperature IR CO signal IR CO2 signal 6 544 0102030405060 70 Time, min Well Sample Depth, mWeight, mg S , mg/g S , mg/g TOC, % T , °C 1 2 max YW2C-625224 6468 71.3 0.50.48 0.287 464 Fig. 5 a Relationship between S and depth of YW2 well in the platform of Tarim Basin; b pyrogram of low-TOC samples with depth of 1 pd 6454 m; and c pyrogram of low-TOC samples with depth of 6468 m from the Middle–Upper Ordovician Formation in the YW2 well, Tarim pd Basin 1 3 FID signal millivolts, FID FID signal millivolts, FID Depth, m IR CO signal mv IR CO signal mv 2 1504 Petroleum Science (2020) 17:1491–1511 TOC of effective S of effective Porosity of effective source rock, % Q , kg/m source rock, mg/g source rock, % 0 1 0 4 01 0 1.5 TOC of ineffective rock, % 0 1 S of ineffective Porosity of Q , kg/m rock, mg/g rm ineffective rock, % TOC = 0.5% 01 0 1.5 0 1 Lianglitage Upper Tumuxiuke Ordovician Sample1 Sample2 Sample3 Middle Yijianfang Ordovician Sample4 Lower Ordovician Yingshan Mudstone Lime Argillaceous Micritic Powder Oolitic Arenitic Bioclastic FluorescenceOil spot Oil-bearing Sample without Hydrocarbon mudstone limestone limestone crystalline limestone limestone limestone hydrocarbon explusion limestone explusion sample Fig. 6 Distinguish results of effective and ineffective source rocks of Ordovician in YW2 well 0.8 0.7 (a) (b) Ineffective rock Ineffective rock N = 86, YW2 well N = 86, YW2 well Effective source rock Effective source rock 0.7 0.6 0.6 0.5 Population 1 0.5 S /TOC × 100 = 100 0.4 0.4 0.3 0.3 Population 2 0.2 0.2 0.1 0.1 0 0 00.2 0.40.6 0.81.0 00.2 0.40.6 0.81.0 TOC, % TOC, % Fig. 7 S and S characteristics of effective source rocks and ineffective rocks with TOC of YW2 well, Tarim Basin. a S vs TOC; b S vs TOC 1 2 1 2 1 3 S , mg/g System Formation Depth, m Lithology S , mg/g Biomarker location Petroleum Science (2020) 17:1491–1511 1505 are self-generated and retained and exclude those charged to the porosity contrasts of two types of carbonates in from other source rocks when identifying the effectiveness YW2 well. In the process of tight oil charging, it is always of low-TOC abundance source rocks. inf luenced by capillary pressure, viscous force and iner- Several evidences can be obtained to prove the tial force (Zou et al. 2013). Effective reservoirs depict a hydrocarbons in samples of YW2 well are self-gener- lower porosity limit within which the oils can accumulate ated and retained. Firstly, according to the Rock–Eval (Jiang et al. 2017). In Tarim Basin, the effective carbon- pyrolysis experiment results, the effective source rocks ate reservoirs generally have porosity greater than 1.8% with low-TOC generally have characteristics with S / (Pang et  al. 2013). Additionally, the well is located in pd 1 TOC×100 ≥ 100 mg/g TOC, HI (S /TOC×100) ≥ 50 mg/g, the slope adjacent to the depression lack of faults and is and extremely low porosity (Figs. 6 and 7). The relatively developed low permeability (Fig. 1). Thus, the studied high S /TOC values suggest that the actual amount of interval cannot be regarded as effective reservoir rocks residual hydrocarbons is relatively large (Fig. 7a) so that for migrated oils. the kerogens can generate sufficient hydrocarbons to result in enough dynamic force to against the capillary 4.2 Oil–source correlation resistance and expel outward to be referred as effective source rocks. On the other hand, the relatively high value Hydrocarbon expulsion has been identified from the poten- of HI (> 50 mg/g) shows the fact that the kerogen in the tial carbonate source rocks in Middle–Upper Ordovician in source rocks can continue to generate and expel hydro- Tarim Basin. Oils from the Middle–Upper Ordovician source carbons (Fig. 7b). rocks have features including a relatively low amount of Secondly, reservoir porosity in effective source rock gammacerane, 24-isopropylcholestanes, C homohopanes, interval is much higher than those in the non-source rock 24-norcholestanes, C regular steranes and C dinosteranes 28 30 interval. It may be due to the organic porosity present in (4α, 23, 24-trimethylcholestanes) yield a V-shaped regular the effective source rock by hydrocarbon generation and sterane distribution (Zhang et al. 2000, 2002a, 2004; Wang expulsion (Modica and Lapierre 2012; Chen and Jiang and Xiao 2004; Li et al. 2015; Huang et al. 2016). 2016). According to the logging data of the study interval, Based on the characteristics of biomarkers, an oil–source the porosity is poor developed, which ranges from 0.10% correlation was performed between the crude oil samples to 1.34% (Fig. 6). Based on the organic porosity calcula- from discovered oil accumulations and potential effective tion model (Chen and Jiang 2016), the average of esti- carbonate source rocks. Results suggest that there are many mated organic porosity reaches 1.2%, which is accordant similar characteristics between potential effective low-TOC (a) Sample 1 29 (b) Sample 2 YW2, O , 6459.75 m YW2, O , 6448.1 m 2y 2y C C 28 21 (c) Sample 3 (d) Sample 4 YW2, O , 6465.8 m YW2, O , 6475.3 m 2y 2y 21 28 Fig. 8 Regular sterane characteristics of Upper–Middle Ordovician source rocks with hydrocarbon expulsion in YW2 well, Tarim Basin (m/z = 217) (Sample locations are shown in Fig. 6) 1 3 1506 Petroleum Science (2020) 17:1491–1511 27 29 (a) YM2-12-4, O ,5889.09-5985 m 1-2y YM2-12-14, O, 5775.5-5915 m YM2-1H, O , 5918.5-6203 m 2y (b) C 27 H7-2, O , 6534-6595 m 2+3 H9001, O , 6457.9-6680 m 1y XK4, O , 6834.05-6850 m 2y Fig. 9 Oil regular sterane distribution characteristics of Ordovician in Tabei area, Tarim Basin (m/z = 217, and well locations are shown in Fig. 1a). a Crude oil from Yingmaili oilfield; b crude oil from Halahatang oilfield source rocks in well YW2 and crude oils in the Yingmaili residual hydrocarbon amounts of mature source rock inter- and Halahatang oilfields in the Tabei area, including low vals that have expelled hydrocarbons are always greater than C regular steranes and a ‘V’-shaped trend of sterane dis- or equal to critical hydrocarbon amount at expulsion thresh- tribution (C, C and C regular steranes) (Figs. 8 and old (Fig. 10a). 27 28 29 9), which indicate that crude oils may be originated from Furthermore, 43 rock samples were also selected from the effective source rocks with low-TOC abundance in the typical non-source rock (that cannot expel hydrocarbon) Tabei area. intervals of TC1 and TZ10 wells in Tarim Basin (loca- tions are shown in Fig. 1), to compute residual hydrocarbon 4.3 Method verification amounts based on the above-mentioned method and model. Results indicate that of non-source rock interval samples Fifteen samples from typical source rock wells, including incapable of hydrocarbon expulsion, actual residual hydro- KN1, TD1 and TD2 wells (locations are shown in Fig. 1, Li carbon amount is 100% less than critical amount at expul- et al. 2010), were used to verify the above model. Based on sion threshold (Fig. 10b). the method and model, critical and actual residual hydro- Verification results indicate that the proposed method and carbon amounts were calculated. As results indicate, actual models are useful to identify effective source rocks which 1 3 Petroleum Science (2020) 17:1491–1511 1507 100 6 (a) Qr N = 15 Present-day TOC 80 Q rm 50 3 0 0 KN1 KN1 KN1 KN1 TD1 TD1 TD1 TD1TD2 TD2TD2 TD2TD2 TD2TD2 3.0 3.0 (b) Qr N = 43 Present-day TOC 2.5 2.5 Qrm 2.0 2.0 1.5 1.5 1.0 1.0 0.5 0.5 Fig. 10 Relationship between actual and residual hydrocarbon at expulsion threshold amounts of confirmed typical source rocks and non-source intervals, Tarim Basin. a Typical source rocks (well locations are shown in Fig. 1a); b non-source rocks (well locations are shown in Fig. 1a) have expelled hydrocarbons from non-source rocks and can Rock–Eval data, reservoir volumetric parameters, oil den- thus be applied in the identification of effective low organic sity, water salinity, formation pressure and temperature. matter abundance source rock in carbonate successions. This requires the data of the application area is relatively The method proposed in this study takes mass bal- sufficient. Meanwhile, during the process of determin- ance principle as basis, by determining and comparing ing actual residual hydrocarbon amount, we need to iden- the hydrocarbon expulsion threshold and actual residual tify whether the residual hydrocarbons in the sample are hydrocarbon amount, to identify the samples reaching migrated or self-generated. This part is quite essential expulsion threshold as effective source rocks. Compared and needs multiple means to comprehensively identify with traditional methods to identify effective source rocks so as to eliminate the influence of migrated hydrocar- using the present-day TOC values, the proposed method is bons. In addition to the methods discussed in Sect. 4.1 in an innovation. It eliminates the influence of present-day this study, Loucks and Reeds (2014) as well as Li et al. TOC values changing in different evolution stages. The (2018) provided effective methods to identify migrated evaluation method may be more objective, especially for hydrocarbons. the source rocks at high evolution stage, such as those in the Tarim Basin and Sichuan Basin in China. Currently, 4.4 High original TOC and original hydrogen index lacustrine carbonate source rocks have also been noted of effective TOC rocks pd during recent years (Liu et al. 2019). For example, the carbonate source rocks might have act as important oil In this study, the interval depth for samples is 86 m and contributors in the lacustrine Mahu sag (Cao et al. 2019). the value of VR (1.31%–1.41%) is similar; hence, HI at Although the study case in this study is for marine car- present day can be used to differentiate diverse populations bonate rocks, based on the principle and methods of mass of organic matter. Closer examination suggests the presence balance, the identification of effective lacustrine carbon- of two distinct organic matter populations within YW2 sam- ate rocks is also applicable. ples: one population with HI > 50 mg/g and the other with The limitation of the method, as described in meth- HI < 50  mg/g (Fig. 7b). Utilizing the method proposed by odology section, involves many parameters, such as Chen and Jiang (2015) on kerogen kinetics, the original 1 3 3 3 Residual hydrocarbon, kg/m Residual hydrocarbon, kg/m TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TAC1 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 TZ10 Present-day TOC, % Present-day TOC, % 1508 Petroleum Science (2020) 17:1491–1511 4.5 Probable contribution of lowT ‑ OC source rock Table 3 Calculation results of hydrocarbon amount at expulsion pd threshold and actual residual hydrocarbon amount of Middle–Upper to hydrocarbon resources Ordovician Formation in YW2 well in the platform of Tarim Basin Previous controversy on the source of marine oils in Tarim Amount Minimum Average Maximum Basin’s platform concentrated on different opinions from 3 3 Q, m /m 0.352 0.353 0.356 rag the views of geochemistry and geology. Based on the pre- 3 3 Q, m /m 0.00190 0.00200 0.00210 rwg vious studies on geochemical biomarkers parameters and 3 3 Q, m /m 0.0760 0.0800 0.0820 rog carbon isotope characteristics, it is reported that the marine Q , kg/m 0.0640 0.0970 0.106 ro hydrocarbons mainly come from Middle–Upper Ordovician Q , kg/m 0.402 0.410 0.418 rm source rocks (Zhang et al. 2000, 2002b, 2004, 2007; Wang Q , kg/m 0.0340 0.554 2.953 and Xiao 2004; Zhao et al. 2008; Li et al. 2008; Wang et al. 2014). However, recent data indicate that the organic matter contents of carbonate rocks in the Middle–Upper Ordovician hydrogen index (HI ) of the above two populations is esti- are commonly developed low for the oil/gas accumulations mated and the kerogen types of them are further identified in the basin (Fig. 1). Therefore, the Cambrian–Lower source according to the values of HI . Results show that the HI rocks with high present-day organic matter abundance are 0 0 values of population 1 and 2 are 870 mg/g and 440 mg/g, regarded as the main source for widespread distribution respectively. The kerogens of population 1 are identified of of hydrocarbon accumulations in the carbonate platform Type I and that of population 2 is of Type II. The compo- successions in the basin (Pang et al. 2016). Nevertheless, nents statistical data of optical kerogen organic macerals according to the third round of National resource assessment in well YW2 clarify the fact that there are kerogens from that was based on contribution of high abundance Cambrian pelagic algae with ≥ 80% of sapropelinite and kerogens from source rocks, the predicted in place resources of oil, gas benthic algae with ≥ 20% of provitrinite (similar with vit- and oil equivalent in Tazhong area, is 0.947 × 10   tons, 9 3 8 rinite) (Table 4). 473.2 × 10  m and 1.324 × 10  tons, respectively. However, The effective low-TOC carbonate source rocks are all the 3P reserves of natural gas and total oil equivalent alone 9 3 9 with type I kerogen (Fig. 7b). We use the method proposed are 594.3 × 10  m and 1.041 × 10 tons at present (Yang by Chen and Jiang (2016) to estimate the initial TOC con- 2012), more than or close to total resources of the assess- tent of effective low-TOC source rock. The TOC recovery ment. Similarly, in Tabei area, the oil, gas and oil equivalent 9 9 3 9 coefficient (TOC /TOC) ranges from 2.5 to 3.3 with an aver- resources are 1.816 × 10 tons, 820.4 × 10 m and 2.47 × 10 age of 2.9. When present-day TOC is 0.5%, the T OC can tons, respectively, while the present 3P reserve of oil has reach about 1.5%. The result is consistent with that by Pang been higher than 3.0 × 10 tons (Yang 2012), implying the et al. (2014). When source rock reaches mature stage, both presence of additional source rocks. sufficient organic matter (quantity) and good kerogen type Employing the method of hydrocarbon generation and (quality) play crucial roles in hydrocarbon generation and expulsion, quantities of hydrocarbon expulsion from the expulsion. Figure 7 also shows when TOC is less than 0.5% Middle–Upper Ordovician effective carbonate source rocks in carbonate succession, there are two types of carbonates with low-TOC in Tazhong and Tabei areas had been pre- pd for ineffective source rocks. One is that poor type of kero- liminarily estimated (Pang et al. 2018). The expelled amount gen to generate any significant amount of oil; the second is of hydrocarbons from the Middle–Upper Ordovician in that although kerogens with good types, low TOC in them Tarim Basin’s platform was estimated to be 4.09 × 10 tons could not generate sufficient hydrocarbons amount to meet oil and 13.17 × 10 tons oil equivalent, respectively. If a pro- the required threshold. portion of 10% in the expelled hydrocarbons can be trapped and accumulated in carbonate platform successions in the Table 4 Maceral compositions of kerogen in Ordovician of YW2 well Well Formation Depth (m) TOC (%) Sapropelinite group Exinite group Vitrinite-like group Inert group (%) (%) (%) (%) YW2 O y 6448.1 0.326 70 3 21 6 YW2 O y 6459.75 0.230 78 1 20 1 YW2 O y 6465.8 0.224 80 0 14 6 YW2 O y 6468.7 0.287 80 4 16 0 1 3 Petroleum Science (2020) 17:1491–1511 1509 basin, combined with the resources of Cambrian–Lower low in TOC or too poor in quality of organic matter, carbonate source rocks considered in the third round of cannot be an effective source rocks. National resource assessment, the phenomenon that the esti- mated resource potentials lower than the 3P reserves can Acknowledgements This study was financially supported by the Sci- be explained. This provides insights for the longtime con- ence Foundation of China University of Petroleum, Beijing (Grant No. troversy between geologists and geochemists regarding the 2462020BJRC005) and the Joint Funds of National Natural Science major source rocks contributing to hydrocarbon resources Foundation of China (Grant No. U19B6003-02) . We appreciate the Tarim Oilfield Company, PetroChina, especially the Research Institute in carbonate platform in the basin. This also means that the of Exploration and Development, for providing background geological effective low-TOC source rocks in Middle–Upper Ordo- pd data and permission to publish the results. We also thank the review- vician succession can also be significant for the resource ers for their constructive comments and suggestions that improved the contribution of hydrocarbon accumulations in the basin. manuscript. Open Access This article is licensed under a Creative Commons Attri- bution 4.0 International License, which permits use, sharing, adapta- tion, distribution and reproduction in any medium or format, as long 5 Conclusions as you give appropriate credit to the original author(s) and the source, provide a link to the Creative Commons licence, and indicate if changes 1. The use of present-day TOC threshold as a sole crite- were made. The images or other third party material in this article are included in the article’s Creative Commons licence, unless indicated rion for determining effective source rock is arbitrary, otherwise in a credit line to the material. If material is not included in especially for rocks with high maturity. The proposed the article’s Creative Commons licence and your intended use is not method and models in this study evaluated and com- permitted by statutory regulation or exceeds the permitted use, you will pared the hydrocarbon expulsion threshold and actual need to obtain permission directly from the copyright holder. To view a copy of this licence, visit http://creativ ecommons .or g/licenses/b y/4.0/. residual hydrocarbon amount and can be used to distin- guish effective source rocks that have expelled hydro- carbons from the non-source rocks. 2. The free hydrocarbon retained in the potential source References rock interval of the Middle–Upper Ordovician suc- Cao J, Xia LW, Wang TT, et al. An alkaline lake in the Late Paleozoic cession in YW2 Well lies between 0.034  kg/m and Ice Age (LPIA): a review and new insights into paleoenviron- 2.953  kg/m , and the calculated hydrocarbon expul- ment and petroleum geology. 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