The successful practice of the North American shale oil and gas revolution^[1⇓-3] has opened the door for oil in-source exploration^[4], making continuous oil and gas exploration possible^[5-6]. According to the thermal evolution^[7], shale oil and gas can be divided into two types, namely medium-low maturity shale oil (R_o<0.9%), medium-high maturity shale oil (R_o≥0.9%)^[7] and shale gas (R_o>1.55%). In low to moderate maturity shale, oil and gas coexist with unconverted organic matter^[8⇓⇓-11], so its commercial exploitation can be realized only by means of the in-situ conversion technology. At present, the commercially exploited shale oil and gas is proposed based on the oil and gas that has been generated and retained in the medium-high maturity shale. Shale, mudstone, mud shale and tight reservoir in the shale strata are alternatively developed, so when the volume fracturing technology by horizontal wells is used to develop medium-high maturity shale oil and gas, shale strata with a certain thickness will be treated as the same target layer. Under this condition, the produced oil and gas may come from strata with different lithologies. From the perspective of commercial development, shale oil and gas is a concept of a certain volume of strata in the shale series. For the purposes of shale oil and gas characteristics and commercial development, this study proposes that shale oil and gas refer to the oil and gas that occurs in organic-rich shale (type I or II kerogen with TOC>2%)^[12]. When shale layers are used as the development units, the ratio of isomeric alkanes and n-alkanes with the same carbon number of the extractions and crude oil in the corresponding reservoir intervals is used as identification standard to determine the source of produced oil and gas^[13]. When the oil and gas produced from the shale layers contribute more than 50%, it is called shale oil and gas. When the oil and gas produced from tight layers contribute more than 50%, it is called tight oil^[13]. According to the characteristics of lithologic association in shale strata, shale oil and gas can be divided into three types: pure shale type, mixed type, and interlayered type. The pure shale type refers to that the production layer is mainly organic-rich shale, which is the main source of the produced oil and gas; the mixed type refers to that the organic-rich shale are interbedded with organic-lean rocks (referring to type I or II kerogen with TOC<2%), and the produced oil and gas are mainly from organic-rich shale; the interlayered type refers to that the organic-rich shale are interbedded with tight reservoirs. The thickness of a single tight reservoir is generally less than 3 m. The produced oil and gas are mainly sourced from organic-rich shale.

Many studies have been carried out on the estimated ultimate recovery (EUR) of shale oil and gas, most of which are semi quantitative-qualitative studies based on engineering factors and limited geological data, including the horizontal well length^[14-15], the number of fracturing segments^[16], the volume of fracturing fluid^[16], the volume and concentration of proppant^[16], the number and spacing of perforation clusters^[17⇓-19], shut-in time after fracturing^[18], production pressure difference^[17], etc. The above results do not contain in-depth study on the relationship between the geological parameters of shale oil and gas and EUR, but only focus on qualitatively understanding the influence of some parameters on EUR, such as total organic carbon content^[16], clay volume content^[19], brittleness index^[20], total porosity^[14], permeability^[21], oil saturation^[14], gas saturation^[20], gas-oil ratio^[22-23], formation pressure gradient^[24], and effective shale thickness^[25], instead of providing their relationships quantitatively. Since the geological parameters are the key to control EUR. Around 30% of the production wells in developed shale oil and gas regions of the U.S. are, however, unable to reach the EUR that would meet the lower limit of commercial EUR^[26], because the relationships between key geological factors and EUR are not clear yet, which results in inadequate sweet spot selection and unsuitable engineering and technical treatments.

It is indicated that the uncertainty of the factors controlling the EUR of shale oil and gas and their relationships directly restricts the selection of sweet spots and the choice of targeted engineering treatments, and consequently impacts the development effects and economic benefits of shale oil and gas. To solve the above key geological problems, this study takes the shale oil and gas in the Lower Member of Cretaceous Eagle Ford Formation in the U.S. Gulf Basin as an example to analyze the key geological parameters controlling the EUR of shale oil and gas by using a large amount of assay and production data. In addition, the control effects of the key geological parameters on the EUR of shale oil and gas and their mutual relationships are discussed so as to provide a basis for the selection of sweet spots of shale oil and gas and the formulation of targeted engineering technical schemes.

The Gulf Basin is located in southern Texas of USA (Fig. 1), and the sedimentary environment is controlled by multiple geological tectonic events^[27-28]. The Eagle Ford Formation was developed in the sedimentary environment of the Paleo-oceanic continental shelf in the Middle and Late Cretaceous (about 85 Ma ago), directly covering the carbonate strata deposited in the Late Triassic and Jurassic^[29]. The depocenter of the Eagle Ford Formation is located near the exit of the present North American inland sea. During its deposition to ca. 5 Ma, the Eagle Ford Formation had been in the process of continuous burial depth. After 5 Ma, it began to slowly rise and suffer denudation. The Eagle Ford Formation is a U-shaped outcrop distributed in the northern and southwestern part of the basin, dipping toward the southeast into the Gulf of Mexico^[30]. The burial depth of the Eagle Ford formation on land is about 1500 m to 4900 m, with an average thickness of 76 m^[31]. Based on lithology and logging characteristics, the Eagle Ford Formation can be vertically divided into the Upper Eagle Ford Formation (UEF) and Lower Eagle Ford Formation (LEF)^[32-33]. The LEF is the currently produced layers, where three depocenters are developed (Fig. 1). It covers an area of about 17.5×10⁴ km² with a maximum thickness of 63 m and an average thickness of 45.3 m, and it has good sealing conditions. It is overlain by the UEF mudstone, and locally by the Austin Chalk limestone; and underlain by the Buda limestone and locally by DelRio marl^[34]. Black and light gray calcareous mudstone are well developed in the UEF. The average content of carbonate minerals is about 67%, the average TOC is 3.2%, and kerogen Ⅱ-Ⅲ is mainly developed^[35]; the LEF is mainly composed of black shale and mudstone. The average content of carbonate minerals is 58%, the average content of clay is 16.5%, and the average TOC is 4.23%, with type II kerogen developed^[32-33].

From northwest to southeast, the R_o of the LEF gradually increases (Fig. 1) and three oil and gas production zones of black oil, wet gas/condensate oil and dry gas are developed in sequence^[36]. Regionally, the produced oil and gas are mainly controlled by the maturity of organic matter. The LEF is the main production zone. The current development area is about 3×10⁴km², and the burial depth of the production layer is 1500-4500 m. The number of the shale oil and gas production wells in the LEF is 1000 in 2010 and more than 30,000 in 2019. The technically recoverable reserves of oil and natural gas in the LEF are about 13×10⁸ t and 1.9×10¹²m³, respectively^[37].

The data in this study comes from the 991 groups of analysis and logging data from 72 systematic coring wells in the LEF, including the oil, gas and water production and logging data and the crude oil and natural gas analysis data of 1317 horizontal production wells, and the initial formation pressure and formation pressure gradient data obtained from formation pressure test of 226 production wells. The R_o of the shale in the study area is between 0.6% and 2.2%, covering the entire range from black oil, condensate oil and wet gas to dry gas, providing a reliable data basis for studying the key geological parameters controlling the EUR of shale oil and gas.

The economy of shale oil and gas depends on two key indicators, namely single well cost and single well EUR^[39]. The accurate acquisition of single well EUR is the basis for the study^{[40⇓⇓-43]}. The single well EUR refers to the cumulative oil and gas production by the end of a production well. The production cycle of a shale oil and gas production well is generally 20 to 30 years. Due to the short history of shale oil and gas production, however, there is no single well EUR of a complete production cycle. Therefore, it is necessary to use production wells with a certain production time to predict EUR. At present, the most common models for predicting single well EUR are MHD model^[44] and Duong model^[45]. MHD model follows the hyperbolic decline trend of oil production in the early stage and the exponential decline trend in the late stage. It predicts EUR by setting a predetermined minimum decline rate, which belongs to the empirical parameter prediction. Duong model is mainly proposed for fractured shale reservoirs. Based on the prediction of empirical parameters, it is considered that the production of the single well presents a linear flow state in the production cycle, and the cumulative oil and gas production has a linear relationship with the time in the condition of the logarithmic coordinates. Thus, the prediction accuracy is high.

In this study, the MHD model^[44] and the Duong model^[45] are used to predict the EUR of oil (black oil or condensate oil) and natural gas, respectively. In addition, the EUR predicted by two models are calculated, and the average value of the sum of the EUR of oil and natural gas is taken as the final EUR of shale oil and gas, so as to minimize the error between historical fitting and prediction and maximize the EUR prediction accuracy. Under the same geological conditions and horizontal well length, the initial production and EUR of the single well will change significantly with the progress of engineering technology. Prior to 2015, the engineering technology used for shale oil and gas exploration in the LEF was basically similar. In order to reduce the influence of engineering factors on EUR of shale oil and gas, this study took 1317 horizontal production wells which were put into production in the LEF during 2009-2012 and have similar engineering technological conditions as the research objects.

The EUR normalization method was used in this study. Taking the average length of horizontal section (1450 m) of all horizontal wells as the standard, the EUR of horizontal production wells having the same geological and engineering technological conditions was normalized. At the same time, the volume of proppant and fracturing fluid per meter of horizontal production well were normalized:

On the basis of research above, EUR value during certain period in production wells of Eagle Ford area has been determined, in which the lowest value suitable for this area is 3×10⁴ m³.

The geological parameters that control the EUR of shale oil and gas are shale source parameters and derived parameters. The shale source parameters refer to the geological parameters determined by the original depositional environment. Source parameters are the basis for the formation of shale oil and gas, including kerogen type, TOC, V_c, H and lithology of the shale at roof and floor. The derived parameters are developed from the source parameters which undergo the thermal and structural evolution, including ϕ_t, ϕ_h, K_a, K_e, ϕ_f, formation pressure gradient, S_o, S_g, S_h, GOR, CGR, WGR, ρ_o, ρ_g, and geostress.

Under the same engineering technological conditions, EUR of shale oil and gas is mainly controlled by the geological factors, such as shale reservoir capacity, flow capacity, resources, and fracability. The reservoir capacity is controlled by the TOC, ϕ_t and ϕ_h of the shale; the flow capacity of the shale oil and gas is controlled by theK_a, K_e, fracture ϕ_f, formation pressure gradient, GOR, CGR, and WGR. The amount of oil and gas resources is controlled by the S_o, S_g, S_h, ϕ_t and ρ_o of shale. Shale fracability is affected by the B and ground stress of shale (Fig. 2). The preservation is controlled by the lithology of shale roof and floor, displacement pressure, and transportation capacity through shale faults. Through studying the relationship between the geological parameters and EUR, the controlling factors of EUR and the related geological parameters has been revealed, and the quantitative evaluation for EUR using the key geological factors has been realized.

The oil and gas reservoir capacity of shale refers to the amount of oil and gas stored per unit volume of shale, which largely determines the production capacity of shale oil and gas. The amount of oil and gas per unit volume of shale is mainly controlled by ϕ_h of shale, which can be obtained through ϕ_t and S_h. ϕ_t and S_h of shale are controlled by TOC and R_o. The oil and gas reservoir capacity of shale can be characterized through ϕ_t, S_h, TOC and R_o.

According to the average ϕ_t by log interpretation of 1317 horizontal production wells in the LEF and the corresponding EUR, the EUR and average ϕ_t of the horizontal production wells in the interval corresponding to ϕ_t were calculated at the interval of ϕ_t=1%. The results show that EUR increases with ϕ_t, and there is a good power relationship between them (Fig. 3). Based on the ϕ_t average value of the corresponding coring wells obtained from the assay data of 64 coring wells, the average EUR of all horizontal production wells within 2 km of the corresponding coring well were calculated, and then the average value of ϕ_t and EUR in the interval corresponding to ϕ_t were calculated at the interval of ϕ_t =1%. The results show that the ϕ_t obtained from the core analysis of the coring well and the EUR also have a good power relationship. In addition, the ϕ_t obtained from the core analysis of the coring well and the ϕ_t based on the logging interpretation basically coincide with the trend line of EUR (Fig. 3), which indirectly proves the reliability of the logging interpretation results. Based on the ϕ_h data of 53 coring wells in the LEF, the average ϕ_h was calculated, and the average EUR of all horizontal production wells within 2 km of the corresponding coring well was calculated. The results show that EUR increases with the increase of ϕ_h. There is a very good exponential relationship (Fig. 4).

The TOC and R_o of shale are the main factors that control the EUR of oil and gas. Using the average of the TOC based on logging interpretation from 1057 horizontal production wells in the LEF and the corresponding EUR, the TOC and EUR were classified according to different R_o intervals, and then the average EUR and TOC of horizontal production wells were calculated in the same R_o interval at the interval of TOC=1%. The results show that in the same R_o interval, EUR increases with the increase of TOC, and there is a good logarithmic relationship between them (Fig. 5):

In the Equation (2), the empirical parameters are obtained after the TOC and EUR data of production wells in Fig. 5 are logarithmic function fitted in different R_o intervals (Table 1).

Take the lower limiting value of EUR of 3×10⁴ m³ as the boundary, there is industrial value existed when TOC in Eagle Ford area is larger than 2.3% (Fig. 5). The relationship between EUR and TOC in different R_o intervals is different. When TOC is equal and higher than 3.2%, the EUR of shale oil and gas is mainly controlled by organic porosity. Under the same R_o condition, with the increase of TOC, the amount of retained oil and gas increases, which leads to the increase of single-well ultimate oil and gas production. The EUR also increases with the increase of TOC, presenting better logarithmic correlation (Fig. 5). Thus, TOC can control the EUR to a certain extent. When TOC is less than 3.2%, the inorganic porosity has an enhanced control effect on EUR, and the correlation between EUR and TOC is significantly different from that with TOC equal and higher than 3.2%.

Oil and gas resources are the resource basis for the development of shale oil and gas, which are mainly controlled by shale ϕ_h and H. The properties of shale oil and gas vary greatly with the change of R_o, including black oil, condensate oil and natural gas. Therefore, shale oil and gas resources are also controlled by S_o, S_g and S_h. Here are mainly the relationships between EUR and S_o, S_g, S_hand H.

The average S_h, S_o and S_g of single well obtained by core assay data of 55 coring wells in the LEF and the average EUR of all horizontal production wells within 2 km of the corresponding well show that EUR of shale oil and gas is in close relationship with S_h, S_o and S_g. EUR increases with the increase of S_h, and there is a good exponential relationship between them (Fig. 6a). However, the relationship between EUR and S_h of oil (including black oil and condensate oil), natural gas and hydrocarbons (including black oil, condensate oil and natural gas) is more different. As S_h gradually increases, the oil EUR shows a trend of slow increasing while that of hydrocarbons shows a trend of dramatic increasing and the change trend of natural gas EUR lies between oil and hydrocarbons. Both oil and natural gas produced from the LEF shale in the study area contribute to EUR, and the contribution of natural gas to EUR exceeds that of oil. The change laws of the EUR of shale oil and gas with the increase of S_o are different (Fig. 6b). The EUR of oil and natural gas are in a good linear relationship with S_o, but the their change trend is opposite. As S_o increases, the oil EUR increases, but the natural gas EUR decreases, because with the increase of R_o, the GOR of shale will gradually increase and the proportion of oil in the produced hydrocarbons will gradually decrease, while the proportion of natural gas will gradually increase. The hydrocarbon EUR shows a decreasing trend with the increase of S_o, but the decreasing trend is not as obvious as that of natural gas, because the oil saturation in high- maturity shale is much lower than the gas saturation.

The EUR of shale oil and gas changes differently with the increase of S_g (Fig. 6c). The oil EUR decreases with the increase of S_g, and they both present a good linear relationship; the natural gas EUR increases with the increase of S_g, presenting a good power relationship; the hydrocarbon EUR increases firstly and then decreases with the increase of S_g, presenting a better quadratic polynomial relationship (Fig. 6c.). The relationship between EUR and S_g of oil, natural gas and hydrocarbons is fundamentally controlled by the R_o values of shale. In shale of different maturity levels, GOR and oil and gas components are completely different, which directly determines the value of EUR.

When horizontal well fracturing is conducted in shale reservoirs, there is a certain effective range limit in the vertical direction, which means there is an upper limit of effective shale thickness. When the effective shale thickness exceeds this upper limit, fracturing is invalid. Under current fracturing technology conditions for horizontal production wells in the LEF, EUR is independent of H when H is greater than 65 m (Fig. 6d).

According to the H of 63 coring wells in the LEF and the average normalized EUR of all horizontal production wells within 2 km of the well, average EUR was classified according to different R_o intervals. Average normalized EUR and average H were calculated in the interval of H (i.e., 5 m) to study the relationship between EUR of shale oil and gas and H. The results show that with the increase of H, the EUR of shale oil and gas increases on the whole, but the change laws of the EUR in different R_o intervals are different. When R_o is less than 0.7%, EUR is quite small and basically not controlled by H. When R_o is greater than 0.7%, there is a good linear relationship between them (Fig. 6d). When R_o is in the range of 0.7%-0.9%, EUR increases slightly with the increase of H. When R_o is in the range of 0.9%-1.0%, EUR is small when H is small, but it increases significantly with the increase of H. When R_o is greater than 1.0%, EUR is larger when H is small, and with the increase of H, EUR also increases significantly. When R_o is between 1.0% and 1.5%, the change range of EUR is greater than that when R_o is greater than 1.5%.

The flow capacity of shale oil and gas refers to the flow capacity of oil and gas in shale, which is mainly controlled by shale K_a, K_e, ρ_o, GOR, CGR, WGR, original formation pressure, formation pressure gradient, R_o and other parameters. Under certain conditions, the flow capacity controls the initial production rate and EUR of shale oil and gas production wells.

K_a and K_e were ranked respectively, the average value of K_a and K_e were obtained at a certain interval, and average EUR of oil, natural gas and hydrocarbons were calculated in the interval of corresponding K_a and K_e respectively. The results show that as K_a and K_e increase, the oil EUR oil increases firstly and then decreases; the hydrocarbon EUR is in a good logarithmic relationship with K_a and K_e; and the natural gas EUR is in a good logarithmic relationship only with K_a. With the increase of K_e, EUR decreases firstly and then increases (Fig. 7a, 7b). The reason for the above changes is that K_a and K_e increase with the increase of R_o, resulting in corresponding changes in S_o, S_g and S_h, which ultimately affects the EUR of shale oil and gas.

In shale with different maturity, the nature and proportion of oil, gas and water are completely different, which directly determines the relationship between EUR of shale oil and gas and GOR, CGR and WGR.

The EUR of shale oil and gas in the LEF increases with the decrease of ρ_o, which is closely related to the fact that ρ_o decreases with the increase of R_o (Fig. 8a).

Panja, et al. proposed that the initial GOR was high, and the oil and gas production was correspondingly high^[46]. The EUR in the LEF increases firstly and then decreases slowly with the increase of GOR. When GOR is greater than 650 m³/m³, the EUR decreases slowly with the increase of GOR. With the increase of CGR, the EUR is basically unchanged at first, and then decreases rapidly. When CGR is greater than 15 m³/10⁶m³, the EUR decreases rapidly with the increase of CGR. With the increase of WGR, EUR slowly increases firstly and then decreases rapidly. When WGR is over 0.5 m³/m³, the EUR decreases rapidly with the increase of WGR (Fig. 8b).

Similarly, controlled by the thermal maturity of shale, different R_o determines the different relationship between EUR and formation pressure gradient and original formation pressure. Based on the formation pressure gradient of 220 horizontal production wells in the LEF and the original formation pressure of 226 horizontal production wells, the average EUR in the corresponding interval was calculated and normalized at a certain interval of formation pressure gradient and original formation pressure to study the relationships between EUR of shale oil and gas and formation pressure gradient and original formation pressure. The results show that EUR is in a good quadratic polynomial relationship with formation pressure gradient and a good cubic polynomial relationship with original formation pressure (Fig. 9). With the increase of formation pressure gradient and original formation pressure, EUR presents a change trend of increasing firstly and then decreasing, and the formation pressure gradient and original formation pressure corresponding to peak EUR are about 1.45 MPa/100m and 57 MPa, respectively.

The degree of shale thermal evolution directly deter-mines oil, gas and water saturation and oil and gas properties in the shale, and ultimately affects the EUR of oil, gas and hydrocarbons in the shale. Based on the oil EUR of 1,120 horizontal production wells in the LEF, the natural gas EUR of 709 horizontal production wells and the hydrocarbon EUR of 1,315 horizontal production wells, the average values of EUR and R_o in the corresponding interval were calculated at certain intervals of R_o respectively, to study the relationship between EUR of shale oil and gas and R_o. The results show that there is a good quadratic polynomial relationship between oil EUR and R_o. As R_o increases, the oil EUR increases firstly and then decreases, and the R_o corresponding to the peak EUR is 1.25%. The natural gas EUR and R_o are in a good cubic polynomial relationship. As R_o increases, the natural gas EUR increases firstly and then decreases slowly and the R_o corresponding to peak EUR is 1.55%. The hydrocarbon EUR is also in a good cubic polynomial relationship with R_o, which increases firstly and then decreases with the increase of R_o. The R_o corresponding to peak EUR is 1.45% (Fig. 10). The analysis results on Fig. 5 indicate that under the same TOC condition, the EUR value of a single well increases firstly and then decreases with the increase of R_o, and the R_o corresponding to the turning point is about 1.3% to 1.4% (Fig. 10). The geological control factors are as follows: under the same TOC condition, with the increase of R_o, the amount of retained oil in the shale increases firstly and then decreases, and the gas content increases form low to high level, so EUR is under the joint control of TOC and R_o.

Shale fracability refers to the difficulty degree of shale fracturing, which directly affects the initial production rate and EUR of shale oil and gas. Shale fracability and fracturing effect are controlled by B, V_C, geostress, fractures and micro-fractures^[47]. Fractures or micro-fractures increase the original flow capacity of shale. Meanwhile, hydraulic fractures are initially generated along the development zones of fractures or micro-fractures, further improving the flow capacity of shale. Therefore, fractures or micro-fractures have an important effect on the increase of the EUR of shale oil and gas. Among them, V_C is a key geological parameter that controls shale fracability. The effects of shale B and V_C on EUR are mainly discussed here.

The average value of V_C and B of a single well and the average EUR of all horizontal production wells within 2 km of the corresponding well were obtained by using the V_C and B parameters obtained from assay data of shale cores from 63 coring wells in the LEF, and the data were classified according to different R_o intervals to study relationship between EUR and V_C and B of shale oil and gas. The calculation equation of B is as follows:

Shale fracability is often characterized by B, which is only one characterization parameter of shale fracability. In fact, shale fracability is mainly controlled by V_C. The EUR of shale oil and gas in the LEF shows an overall increasing trend with the increase of B, but its change laws are quite different in different R_o intervals. The larger the R_o is, the more obvious the increasing trend of EUR with the increase of B is. When R_o is less than 0.75%, the increase range of EUR with B is quite small. If the lower limit of EUR for the commercial development of shale oil and gas (3×10⁴m³) is used for the calculation, the existing horizontal well fracturing technology cannot achieve the EUR with commercial development value no matter how high the B of shale is, when R_o is less than 0.85% and fractures or micro-fractures are not developed. When R_o is higher than 0.85%, it is difficult for shale oil and gas to realize the EUR with commercial development value, if B is lower than 75% (Fig. 11a).

The EUR of shale oil and gas in the LEF shows an overall decreasing trend with the increase of V_C. Similarly, there are big differences in the change laws in different R_o intervals. The larger the R_o is, the more obvious the decreasing trend of EUR with the increase of V_C is. When R_o is less than 0.75%, the change range of EUR with the increase of V_C is very small. Similarly, if the lower limit of EUR for the commercial development of shale oil and gas (3×10⁴m³) is used for the calculation, the existing horizontal well fracturing technology cannot achieve the EUR with commercial development value no matter how low the V_C of shale is, when R_o is lower than 0.85% and fractures or micro-fractures are not developed. When R_o exceeds 0.85%, it is also difficult for shale oil and gas to achieve the EUR with commercial development value if V_C is greater than 25% and fractures or micro-fractures are not developed (Fig. 11b). When R_ois lower than 0.85%, EUR changes less with the increase of B and V_C. It is indicated that R_o has a strong controlling effect on the EUR of shale oil and gas^[48].The reason is that the organic pores in the shale are not developed and the GOR is low, so the flow capacity of oil and gas in shale is weak. Thus, V_C plays an important control role in the EUR of shale oil and gas, because the V_C of shale controls the fracability, the adsorbed oil or free oil in the shale and the fracture closure rate and velocity after fracturing. Under the same geological conditions, the higher the V_C is, the more the adsorbed oil in the shale or the less free oil, the greater the fracture closure rate and velocity after fracturing are, and the smaller the final EUR is.

The reservoir capacity, resources, flow capacity and fracability are the four key geological parameters controlling shale oil and gas EUR, including several geological parameters. Based on the analysis of the intrinsic causes of geological parameters controlling the shale oil and gas EUR, it is proposed that the internal geological parameters controlling the EUR of shale oil and gas are TOC, R_o, H, V_C, and formation pressure gradient and fracture porosity. The quantitative model of these six geological parameters and EUR can be established to comprehensively evaluate the favorable area of shale oil and gas.

The EUR of shale oil and gas is controlled by four geological factors: reservoir capacity, resources, flow capacity and fracability. EUR is directly controlled by ϕ_h, K_e, GOR, CGR, ρ_o, B, H,formation pressure gradient and development degree of fractures and micro-fractures. EUR is actually controlled by six geological parameters: TOC, R_o, H, V_C, and formation pressure gradient and fracture porosity.

Under the conditions of the present horizontal well fracturing technology, EUR is independent of H when H is larger than 65 m.

Under the present horizontal well fracturing technology and the lower limit of EUR of 3×10⁴ m³, favorable area of shale oil and gas hardly occur when TOC<2.3%, R_o<0.85% orV_C>25% and fractures and micro-fractures are not developed.

The geological parameters to evaluate the “sweet spots” of shale oil and gas in the areas without developed fractures include TOC, R _o, H, formation pressure gradient and V_C. As for the fracture development areas, the effect of fractures on EUR must be considered, which can be characterized by fracture porosity.

For marine and continental shale oil and gas, the formation and enrichment process and the geological controlling factors and parameters of EUR are basically the same, but the organic matter types and the geological conditions and assemblages are different. Researches on the geological controlling factors of EUR of marine shale oil and gas can provide guidance for the evaluation of continental shale oil and gas “sweet spot” and the EUR prediction.

We acknowledge Dr. Mare Lugler, who provided part of the basic information for this study.

a₁, b₁—empirical parameter, dimensionless;

B—brittleness index, %;

CGR—condensate oil-gas ratio, m³/10⁶m³;

EUR—the estimated ultimate produced oil equivalent of the horizontal production well after normalization, 10⁴m³;

EUR_TOC—the value of EUR corresponding to TOC in different R_o intervals, 10⁴m³;

EUR_i—the estimated ultimate production oil equivalent of the horizontal production well before normalization, m³;

F_i—the amount of fracturing fluid per meter, t/m;

${{\bar{F}}_{i}}$—the average value of fracturing fluid per meter, t/m;

GOR—gas-oil ratio, m³/m³;

H—effective shale thickness, m;

i—production well number;

K_a—air permeability, 10^-3 μm²;

K_e—effective permeability, 10^-3 μm²;

l_i—horizontal length of production well, m;

P_ai—the amount of proppant per meter, t/m;

${{\bar{P}}_{\text{a}i}}$—the average value of proppant per meter, t/m;

R_o—vitrinite reflectance, %;

S_g—gas saturation, %;

S_h—hydrocarbon saturation, %;

S_o—oil saturation, %;

TOC—total organic carbon content, %;

V_Q, V_K, V_G, V_R, V_D, V_S, V_P, V_M, V_A, V_C—the volume fraction of quartz, potassium feldspar, plagioclase, calcite, dolomite, siderite, pyrite, marcasite, apatite, and clay minerals, %;

WGR—water-gas ratio, m³/m³;

ρ_o—crude oil density, g/cm³;

ϕ_f—micro-fracture porosity, %;

ϕ_h—hydrocarbon-bearing porosity, %;

ϕ_t—total porosity, %.