Movable Oil Research Articles

Study on fluid mobility in sandwich-type shale oil reservoir using two-dimensional nuclear magnetic resonance approaches

ABSTRACT Regarding sandwich-type shale oil reservoir characterized by diversified lithologies and complex fluid mobility, we combined one- and two-dimensional (1D and 2D) nuclear magnetic resonance (NMR) core analysis techniques to quantitatively study the movable oil and fluid saturations of rock samples with different lithologies. First, we used 2D T1-T2 NMR to analyze the spectrum curve of the dolomitic mudstone and siltstone samples from a sandwich-type shale oil reservoir at initial and oil-saturated states. We evaluated the occurrence of movable oil saturations in source and reservoir rocks. Then, we analyzed samples of the siltstone serving as the reservoir rock using a centrifuge combined with 1D NMR approach to evaluate the characteristics of movable fluid saturations inside the reservoir. The results showed that the samples of dolomitic mudstone serving as the source rock in the sandwich-type shale oil reservoir in the Lucaogou Formation in Jimsar had the occurrence of kerogen and bitumen signals, the development of small- and medium-scale organic matter pores, and an average movable oil saturation of 15.6%. The siltstone serving as the reservoir rock had an average movable oil saturation of 53.8%, and its movable fluid saturation was positively correlated with porosity and permeability. For samples whose porosity was greater than 12% and permeability was greater than 0.1 mD, their movable fluid saturations usually were higher than 40%. Therefore, siltstone was the preferable diagenetic facies for the development of high-quality reservoirs.

An experimental investigation of improving Wolfcamp Shale-Oil recovery using Liquid-N2-assisted N2 and/or CO2 Huff-n-Puff injection technique

Despite drilling numerous horizontal-hydraulically-fractured wells in unconventional reservoirs, the oil recovery factor (RF) of such reservoirs is still very low (<10%), leaving behind massive unrecovered oil in the formation. Improving the oil RF of unconventional reservoirs requires applying and developing enhanced oil recovery techniques. In this study, the feasibility of improving Wolfcamp shale oil RF using liquid nitrogen (LN2) combined with three cycles of N2 and/or CO2 huff-n-puff injections at reservoir temperature (77 °C) and different injection pressures was investigated. The results revealed that LN2-assisted N2 and/or CO2 huff-n-puff injections improved the Wolfcamp oil RF, outperforming the current-experimental practice of N2, CO2, or natural-gas huff-n-puff injections. Higher oil RFs with less soaking time and fewer cycles were achieved in this study. Combining LN2 with cyclic N2 and/or CO2 injections can result in flow-conductivity enhancement, induced-cracks growth, and oil–gas interaction development throughout the injection to production stages, which enhance the stimulated volumes leading to oil RF improvement. Compared to LN2-assisted N2 huff-n-puff, better performance of injecting CO2 after LN2 was observed on samples of low permeability, particularly when utilizing injection pressure near CO2-MMP, 20.68 MPa, resulted in RF of 53%, 26% higher than injecting N2 at the end of cycle#3. Injecting LN2 with N2 into samples of high permeability (greater than 0.1 mD) has the potential to recover oil up to 57% due to the presence of the moveable oil that can flow easily from deeper areas to surface, unlike the samples of low permeability (<0.1 mD), where oil RF at the end of cycle#3 was 27%. LN2-assisted N2-CO2 huff-n-puff increases the incremental oil RF on low permeable samples, resolving the issue related to the fact that the incremental RF would start declining sharply in the second cycle and as the number of cycles increases when using only N2 injection. From the results observed in this study, a combination of cryogenic treatment and huff-n-puff techniques would be potentially implemented in shale oil reservoirs, opening the opportunity to improve shale oil RF by enhancing the flow-conductivity and increasing the hydrocarbon mobility.

Key Oil Content Parameter Correction of Shale Oil Resources: A Case Study of the Paleogene Funing Formation, Subei Basin, China

Estimating shale oil resources is critical in shale oil exploration, and the pyrolysis parameter S1 is a frequently used parameter to assess the oil amount in shale. However, S1 loses some light and heavy hydrocarbons due to core storage conditions and experimental technology, resulting in underestimating shale oil resources. In this paper, a set of models were developed to correct the light and heavy hydrocarbon losses for S1 based on conventional and multistage Rock-Eval experiments on liquefrozen and room-temperature shales collected from the Funing Formation, Subei Basin. Two types of correction models of heavy hydrocarbon loss for liquefrozen and room-temperature shales were determined by comparing the conventional and multistage Rock-Eval experiments, respectively. The light hydrocarbon loss correction model was obtained according to conventional Rock-Eval experiments on liquefrozen and room-temperature shales. Moreover, the estimation models of adsorbed, free, and movable amounts of oil were determined and validated by the oil saturation index (OSI) method. The results show that the total, adsorbed, free, and movable oil contents can be estimated well by these correction models. A case study from the Funing Formation, Subei Basin, indicates that the higher the content of total oil, the higher the amounts of free and movable oil, indicating that shale with more oil also has a more excellent mobile and developable potential. Organic matter is the main adsorbent for shale oil. Shales with TOC greater than 1.5% generally have greater free (movable) oil amounts, which may be the optimal target for shale oil exploration and exploitation. This study provides an innovative approach to correct the key parameters of shale oil resources, and thus, is crucial for the exploration and development of shale oil in the Funing Formation, Subei Basin.

NMR characterization of fluid mobility in low-permeability conglomerates: An experimental investigation of spontaneous imbibition and flooding

Understanding fluid mobility during spontaneous imbibition (SI) and flooding is important for the enhancement of oil recovery. Many researches on SI, water flooding (WF), and N2 flooding (NF) have been published, but an in-depth understanding of the oil mobility at the pore scale is still inadequate in low-permeability reservoirs. To solve this problem, SI, WF, and NF experiments were performed on the low-permeability conglomerates of the Baikouquan Formation and the Urho Formation in the Mahu Sag. Moreover, online NMR was introduced to monitor the oil volume in pores with different sizes in real-time. Considering the wettability, mineral compositions, and pore structure, we established a schematic diagram to reveal the fluid mobility mechanism. The results show that the micropores in the low-permeability conglomerates are more hydrophilic, whereas the other pores are more lipophilic. During SI, the movable oil is mainly distributed in the micropores in the form of clay-bound oil (CBO), which is discharged from the rock through the meso/macropores. High hydrophilicity contributes to a high imbibition rate and oil recovery from SI, while the pore structure only affects the imbibition rate. During WF, the movable oil is contributed by CBO in the micropores and free oil (FO) in the pores controlled by throats >0.3 μm. During NF, the movable oil is mainly distributed in the pores controlled by > 0.1 μm throats, existing as FO and part capillary-bound oil (CAO). The results demonstrate that NF is effective to enhance the oil recovery of tight reservoirs, while WF is only effective for tight reservoirs with better pore structure (high Vr > 0.3 μm).

Identification of Complex Fluid Properties in Condensate Gas Reservoirs Based on Gas–Oil Ratio Parameters Calculated by Optimization Mathematical Model

In the production development stages of volatile oil reservoirs and condensate gas reservoirs, especially in the early stages of production, the phenomenon of high gas–oil ratio often occurs. As a result, the prediction results of oil and gas are greatly deviated from the actual situation, which seriously affects the implementation of potential excavation and increases production operation for condensate gas reservoirs. Therefore, the accurate identification of condensate gas and volatile oil is the key to improve the development efficiency in condensate reservoirs. However, due to the similar geophysical logging response characteristics for condensate gas, volatile oil, and light oil reservoirs, the qualitative identification effect only based on conventional logging is not ideal. Therefore, we propose a method to calculate the gas–oil ratio by introducing gas logging information and use the gas–oil ratio quantitative calculation results to identify condensate gas and volatile oil layers. First, we establish a physical model of the formation components of the condensate gas reservoir. Based on this physical model, we establish the response equations of various logging tools and evaluate the correlation between the gas logging information and the production gas–oil ratio to establish the response equation of gas logging. Then, we comprehensively use the well logging and gas logging response equations to establish an optimization mathematical model, solve the optimization objective function, obtain the relative content of natural gas and movable oil in the formation to calculate the gas–oil ratio parameters, and finally use this calculation result of the gas–oil ratio to quantitatively identify the fluid type. The application results show that the gas–oil ratio quantitative calculation method that we proposed can calculate the gas–oil ratio parameter accurately, and the calculation results are consistent with the formation testing data, which provides technical support for the identification of complex fluid properties in condensate gas reservoirs.

Experimental study on reservoir characteristics and oil-bearing properties of Chang 7 lacustrine oil shale in Yan’an area, China

Abstract The Chang 7 Member shale of the Upper Triassic Yanchang formation in the Ordos basin is a hot spot in petroleum geology research. In this study, considering the Chang 7 shale in the Yan’an area as an example, the full-scale pore size characterization of lacustrine shale was realized based on the scanning electron microscopy image gray correction method, nitrogen and carbon dioxide adsorptions, and high-pressure mercury intrusion tests. In addition, the pore structures and oil-bearing properties of the Chang 7 shale were systematically studied. The results show that the Chang 7 shale is rich in organic matter, with an average total organic carbon value of 4.69% and an average R 0 value of 0.9%. It is in the mature-wet gas (crude oil-associated gas) stage. There are certain differences in the development characteristics and pore size distribution of different types of pores in shale. The statistical results showed that the pore diameters of the intergranular pores and intragranular dissolved pores were significantly larger than the intercrystalline pores of clay minerals and the organic pores. The organic pores in solid bitumen are extremely developed, whereas the organic pores in kerogen are relatively underdeveloped. The lower limit of the effective pore size of shale is 20 nm. The network system composed of inorganic pores-microcracks-organic matter-organic pores and siltstone laminae provides important channels and retention spaces for the migration of shale oil and gas within the source. This study found that the proportion of movable oil in sandy layers is relatively high, followed by shale with sandy laminae, whereas pure shale has the lowest proportion of movable oil. Therefore, the degree of sandy laminar development, the abundance of organic matter, and the degree of thermal evolution are the key geological factors that control the porosity and oil-bearing properties of shale oil reservoirs.

Evaluation Model and Application of Shale Oil Production Efficiency Under Energy-Depleted Development Mode in Jimsar Sag

In order to reveal the shale oil production mechanism and production efficiency under the energy-depleted development mode, experiments on expulsion oil based on imbibition and elastic energy release under high temperature and pressure were carried out, and nuclear magnetic resonance on-line monitoring was used to observe the production characteristics of shale oil. The experimental results show that the imbibition-expulsion oil mainly occurs in the small-size pore-throat system. Under the condition of high temperature and pressure, the oil-expulsion efficiency is generally less than 2% affected by pore pressure, which is significantly different from the conventional imbibition experiment results. Although elastic-energy expulsion oil occurs in different sizes of pore-throat systems, the oil-expulsion efficiency in large size pore-throat systems is more sensitive to temperature. Overall, the total elastic-energy oil-expulsion efficiency is significantly positively correlated with reservoir physical properties, production differential pressure and temperature, and negatively correlated with crude oil viscosity. Comprehensively considering various geological factors affecting oil-expulsion efficiency, the shale oil production efficiency evaluation model under the energy-depleted development mode is constructed, and the movable oil porosity of shale oil development section in the study area is evaluated. The results show that there is a good positive correlation between movable oil porosity and oil production intensity. The movable oil porosity of dry layer is generally lower than 0.5% and that of poor oil layer is between 0.5% and 1.5%. When the movable oil porosity is between 1.5 and 2.5%, it can be determined as the type II oil layer, and for more than 2.5%, it is the type I oil layer. The single-well evaluation results show that the shale oil “sweet spots” of the Lucaogou Formation in Jimsar Sag are mainly distributed in P2l22−1∼ P2l22−3 and P2l12−1∼ P2l12−3, which is in good agreement with the current development status.

Experimental analysis of matrix moveable oil saturation in tight sandstone reservoirs of the south Ordos Basin, China

Tight oil reservoirs in the south Ordos Basin are characterized by fractured, heterogeneous oil-bearing strata (an oil saturation of less than 55% on average), normal pressure (0.8±) and extra-low permeability (less than 0.3 mD). In the Chang 8 tight sandstone reservoir in Honghe oilfield, micro- and nano-pores, especially those with a pore-throat radius of less than 1 μm, account for more than 90%. Fluid flow in the matrix is non-linear and crude oil flow rates are very low under normal pressure gradients. An improved understanding of oil mobility in a tight matrix is key to further development of normal-pressure tight-oil resources in the continental basin. In this study, constant-velocity and high-pressure mercury injection experiments were conducted using samples of typical tight sandstone cores obtained from the south of Ordos Basin. A new method for reconstructing the full-scale pore-throat distribution characteristics of tight sandstone reservoirs was established successfully, based on which multistage centrifugal tests, tests of low-pressure differential displacement of oil by water, and nuclear magnetic resonance tests were conducted in order to obtain the distribution characteristics of moveable fluid in different pores. The moveable oil saturation (MOS) and degree of oil recovery (i.e. ratio of accumulative oil production to producing geologic reserves) of the core samples under different differential pressures for displacement were determined. As for the tight oil reservoirs in the south Ordos Basin, the moveable fluids are mainly stored in sub-micron (0.10–0.5 μm) pores. For Type Ⅰ reservoirs (k > 0.1 mD), the volume percentage of moveable fluid in pores with a radius larger than 0.5 μm is relatively high (greater than 40%). The degree of oil recovery of water flooding serves as the basis for forecasting recoverable reserves for tight oil reservoirs. Recoverable reserves under water flooding, mainly occur in pores with a radius greater than 0.5 μm. The contribution of Type Ⅰ reserves to oil production is observed to be greater than 60%, and the degree of oil recovery reaches up to 17.1%. These results help improve our understanding on the evaluation and classification of Chang 8 tight sandstone reservoirs in Honghe oilfield and serve as theoretical basis for pilot tests to explore effective injection media and development methods to improve the matrix-driven pressure differences and displacement efficiency for oil.

An ANN model to predict oil recovery from a 5-spot waterflood of a heterogeneous reservoir

Waterflooding is a secondary oil recovery technique in which water is injected into an underground oil reservoir to maintain the reservoir pressure and boost oil recovery. The performance of a waterflood depends on several factors such as reservoir heterogeneity, reservoir fluid properties, flood pattern, etc. Most of the models developed to predict waterflood performance are either for linear systems or involve simplified assumptions for non-linear systems. In this study, we propose a novel, artificial neural network (ANN) model comprised of two hidden layers with 256 neurons each for the performance prediction of a 5-spot pattern waterflood in a heterogeneous reservoir at and beyond water breakthrough. The proposed model can be applied to estimate movable oil recovery efficiency of the waterflood (RFM) as a function of Dykstra-Parsons permeability variation coefficient (V), mobility ratio (M), permeability anisotropy ratio (kz/kx), production water cut (fw), a simple indicator of wettability (WI), and oil/water density ratio (DR) within reasonable accuracy. The MAPE of the proposed model was ∼4% and ∼5% using training and testing data, respectively. Our ANN model recommendation is based on a detailed comparative study against other popular soft computing models, such as adaptive neuro-fuzzy inference system (ANFIS) and support vector regression (SVR). Based on the accuracy and computational efficiency, the ANN model outperforms ANFIS and SVR. AIC and BIC of the proposed ANN model were also the lowest among all applied soft computing tools. The proposed model is tested on two real field cases and compared with a semi-analytical model and an empirical correlation. The presented model shows good agreement with the real field data. The trained ANN model, proposed here, saves computational time in forecasting the waterflood performance compared to a reservoir simulator.

Experimental evaluation of enhanced shale oil recovery in pore scale by CO2 in Jimusar reservoir

With the domestic energy supply increase, exploitation of unconventional shale oil resources has drawn great attention from the industry. In this paper, laboratory studies were conducted to investigate the potential of cyclic CO2 injection process to enhanced oil recovery after primary production in shale oil reservoirs. Experimental results indicated that incremental oil production from CO2 huff-n-puff was obtained. The available literature provides limited information on examination of what pore size recovers the most incremental oil recovery by the applicability of CO2 huff-n-puff in shale formations. In this paper, the cyclic CO2 injection performance on three different reservoir rocks was investigated. The enhanced oil recovery by CO2 huff and puff is not limited to macropores, but the remaining oil in the 0.1-μm pore scale is recovered as well. The moveable oil in the large pores (1 μm<D < 10 μm) is mostly recovered at the first CO2 puff cycle. After the second cycle of CO2 huff-n-puff, oil recovery percentage from the large pores decreases significantly. The formation rocks were divided into 3 types based on the geological condition and petrophysical characteristics: type I、II and III. The incremental oil recovery from the type I rock is higher than type II and III. The oil recovery yields mostly from the pore size 0.1 μm <D < 1 μm.

Practice and cognition of effective water-flooding development mode in Gaotaizi block of ultra-low permeability reservoir

During nearly 25 years of water injection development in Gaotaizi reservoir of LHP oilfield, due to poor reservoir physical properties, poor adaptability of well pattern and difficulty in establishing effective displacement between oil and water Wells, linear water injection, infill adjustment and refracturing tests have been carried out successively. Although certain effects have been seen, the effects are short and unsatisfactory. In this paper, the microscopic pore structure, sensitivity and seepage characteristics of ultra-low permeability high platform reservoir are studied through core laboratory experiments. New technology of nonlinear test and low permeable physical simulation experiment, the research on the rules of the nonlinear characteristics of the reservoir fluid and the characteristics of movable oil through research has been clear about the dragon bubble oilfield high effective displacement distance platform layer, and the new fracturing technology and the development of the technology to adjust the organic combination, the displacement between well and well past into displacement between Wells and joint network, explore the ultra-low permeability reservoir to improve the single well production, new ways to improve the development effect, with the types of low permeability oilfield development effectively.

In-situ SEM characteristics of dispersed organic matter in continental shale with its implication for dessert evaluation--A case study of Paleogene shale in the Cangdong Sag, Bohai Bay Basin, China

Organic matter (OM) in continental shale serves as both the source of oil and gas and the storage space in unconventional petroleum systems. However, directly identifying the types of organic matter under SEM is challenging when simultaneously observing minerals and pores. Kong2 Member(E2k2) of Paleogene in Cangdong sag of Bohai Bay basin is a typical continental shale oil layer in China. Based on the positioning observation technology combining field emission scanning electron microscope (FE-SEM) and fluorescence microscope, the in-situ SEM identification and observation of macerals were carried out, and the identification methods and characteristics of organic macerals were summarized. The results show that: (1) Organic macerals in E2k2 shale are divided into vitrinite, inertinite, liptinite and solid bitumen by external morphology, hardness, brightness, color, protrusion, pore and fracture development of organic matter, and further subdivided into multiple subcategories. Based on the SEM charging effect of the remaining oil, it is further confirmed that the shale movable oil and oil generation potential developed by lipoid group is the largest, while the shale movable oil and oil generation potential developed by vitrinite group and inertinite group is the worst; (2) The organic pores include primary pores and secondary pores. The pores of primary organic matter are derived from the biological structure of primary organic matter, and the secondary organic pores are developed during the thermal maturation of oily organic matter. Clay mineral catalysis, difference of hydrocarbon generation potential and residual pores of primary organic matter control the development of organic pores; (3) Calcareous-dolomitic shale and felsic shale are typical lithology formed in relatively dry and humid climate respectively, and the types of organic macerals are significantly different. Although the former has weak total hydrocarbon generation, it has stronger oil generation potential and is worthy of attention in dessert prediction and exploration.

Insights into the pore structure and oil mobility in fine-grained sedimentary rocks: The Lucaogou Formation in Jimusar Sag, Junggar Basin, China

Unconventional shale/tight oil resources in fine-grained sedimentary rocks play essential roles in global energy structure. Fine-grained sedimentary rocks are characterized by complex pore assemblage and connectivity. Insights into the links between pore structure and movable oil are important for exploration and production of tight/shale oil or gas in fine-grained sedimentary rocks. A series of analyses including thin sections, mercury injection capillary pressure (MICP), and nuclear magnetic resonance (NMR) were carried out to unravel the linkage between pore structure and oil movability. Various centrifugation speeds were used in the NMR tests to remove the movable oil to obtain the movable oil saturation corresponding to various centrifugation speed. Fractal dimension is calculated from NMR T2 spectrum. Then four types of pore structures were divided according to the parameters derived from the MICP and NMR results, and the characteristics of various pore structure are summarized. From type Ⅰ to type Ⅳ, the threshold pressure, irreducible water saturation (Swi), and the fractal dimension increased while the SHgmax, rapex, T2gm, porosity, permeability, and movable oil saturation decreased. Then the key factors controlling the movable oil saturation were investigated, including permeability, porosity, T2gm, rapex, and mineral composition of the rocks. The movable oil saturation is dominated by porosity, T2gm, fractal dimension, and rapex. Then a quantitative evaluation model of the movable oil saturation was established. In addition, the NMR logs and the derived parameters were utilized to evaluate the reservoir quality and pore structures in a single well. At last the T2 value of 25 ms (the ratio of the T2 components >25 ms to the total T2 components) was used to calculate the movable oil saturation in the upper member of the Lucaogou Formation, and the T2 value of 28 ms was used for the lower member of the Lucaogou Formation in the Jimusar Sag. The results are testified by the high-speed (10000 r/min) centrifugation NMR measurements. The results above help improve understanding of tight/shale oil enrichment and provide a new model for calculating the movable oil saturation in fine-grained sedimentary rocks.

Effects of pore structure on the moveable oil saturation in water-driven tight oil sandstone reservoirs

Tight oil sandstones have large oil reserves but low waterflooding efficiency and oil recovery. The movable oil saturation (MOS) is a critical parameter for evaluating oil recovery in water-driven tight oil sandstone reservoirs. However, its controlling factors in tight oil sandstones are still not well understood. In this study, the tight/low-permeability sandstones in the Chang 8 and Chang 9 Members of the Honghe Oil Field in the Ordos Basin (China) provide an opportunity to determine the effects of pore structure on the MOS. Porosity, permeability, thin sections, scanning electron microscopy (SEM), large field-of-view SEM imaging method (MAPS technique), high-pressure mercury intrusion (MICP), and micro-CT scanning were systemically conducted to analyze the pore structure analysis. MOS values were obtained from the relative permeability tests. The results show that porosity, pore-throat size, and the sorting coefficient have no evident relationship with the MOS. Many of the higher-permeability samples even show lower MOS values. Moreover, analysis of micro-CT images before and after waterflooding indicates that the lower-permeability samples tend to swept larger areas than the higher-permeability samples, resulting in greater oil-displacement efficiencies and MOS values. Instead, the cumulative mercury saturation at the apex of the mercury injection hyperbola curve (Sapex), the ratio of the maximum pore-throat radius and the medium pore-throat radius (Rmax/R50), and movable fluid saturation (MFS) show a good linear relationship with the MOS. The displaced oil is primarily from intergranular pores and partly from intragranular pores. The micropores that are widely distributed at the grain-grain contact display low original oil saturation and low oil displacement efficiency. It is proposed that the volume of the well-connected pores that contribute to permeability is the key factor controlling the MOS regardless of the type of rock.

Challenges and countermeasures of log evaluation in unconventional petroleum exploration and development

To promote adaptation of logging evaluation technologies to the development trend of unconventional oil and gas exploration and development era in China, the current situation and challenges of logging evaluation technologies in China are analyzed systematically. Based on the concept of that demand drives technology development, and referring to the international leading technologies, development strategy of logging evaluation technology in China has been put forward. (1) Deepen petrophysics study: mobile 2D NMR laboratory analysis technology for full diameter core should be developed, characteristic charts and evaluation standards of different fluid properties, different pore structures and different core exposure times should be established based on longitudinal and traverse relaxation spectra; in-depth digital rock experiment and mathematical and physical simulation research should be carried out to create innovative logging evaluation methods; acoustic and electrical anisotropy experimental analysis technology should be developed, and corresponding logging evaluation methods be innovated. (2) Strengthen target processing of logging data: precise inversion processing technology and sensitive information extraction technology of 2D NMR logging should be developed to finely describe the micro-pore distribution in tight reservoir and accurately distinguish movable oil, bound oil, and bound water etc. The processing method of 3D ultra-distance detection acoustic logging should be researched. (3) Develop special logging interpretation and evaluation methods: first, mathematical model for quantitatively describing the saturation distribution law of unconventional oil and gas near source and in source should be created; second, evaluation methods and standards of shale oil and deep shale gas “sweet-spots” with mobile oil content and gas content as key parameter separately should be researched vigorously; third, calculation methods of pore pressure under two high-pressure genetic mechanisms, under-compaction and hydrocarbon charging, should be improved; fourth, evaluation method of formation fracability considering the reservoir geologic and engineering quality, and optimization method of horizontal well fracturing stage and cluster based on comprehensive evaluation of stress barrier and lithologic barrier should be worked out.

Pore Structure, Fractal Features, and Oil Content Evaluation of Lacustrine Shale: A Case Study of First Member of Paleogene Shahejie Formation, NE China

The complex and heterogeneous pore structure and oil content of lacustrine shales introduce significant challenges in the exploration of shale petroleum systems. To further expand our geological understanding of lacustrine shales and provide guidance for hydrocarbon exploration, in this study, based on programmed and improved Rock-Eval pyrolysis, total organic content (TOC) measurements, scanning electron microscopy (SEM) observations, and N2 adsorption (NA) experiments, a systematic evaluation of the mineral composition, geochemical features, pore structure, and oil contents of the third member of the Paleogene Shahejie Formation (Es3) shale in the typical lacustrine hydrocarbon enrichment sag (Nanpu Sag, Bohai Bay Basin) is conducted. The fractal theory is selected to quantify the pore system’s heterogeneity; also, the relationships between the pore structure parameters and the oil contents and mineral composition are revealed. Our results reveal the geochemical features of the Es3 shale are excellent, and thus, they can be classified as a set of high-quality source rocks (average TOC of 4.2%, mainly type II kerogen, and in the mature stage). Based on the SEM and NA analyses, the intercrystalline pores dominate the pore system. Moreover, the mesopores contribute the most specific surface area (SA) and pore volume (PV) to the samples (average contribution rates of 74.7 and 75.0%, respectively). The fractal dimensions have relatively strong positive correlations with PV and SA, which means more heterogeneous and complex pore structures provide more storage space and adsorption sites for shale oil accumulation. The clay mineral content is the most important factor which controls the pore structure parameter, and high clay content indicates high SA and PV. According to proposed numerical movable and adsorption hydrocarbon calculation models, the TOC content is the dominant factor controlling the movable and adsorption oil contents, but other factors’ impact also cannot be ignored. Our study not only provides guidance for shale oil exploration in the study area but also broadens our understanding of the oil contents of lacustrine shale.

A New Evaluation Method of Shale Oil Sweet Spots in Chinese Lacustrine Basin and Its Application

Compared with the marine shale from North America, Chinese lacustrine basins have more complex geological and reservoir conditions, which makes the selection of sweet spot intervals in the shale oil reservoir particularly difficult. It is thus crucial to accurately predict the shale oil sweet spots for effective exploration and development of shale oil in a lacustrine basin. In this paper, we propose an innovative evaluation method of shale oil sweet spots, which considers five primary parameters (i.e., total oil content, movable oil ratio, reservoir pressure coefficient, permeability, and rock brittleness index) to construct a comprehensive weighting factor, which is used to quantitatively identify a favorable shale oil reservoir. This method firstly constructs an evaluation function for each of the parameters, and then calculates a comprehensive weighting factor to determine the shale oil sweet spot. Statistical results show that the oil production of formation testing intervals have a good positive correlation with the average value of the comprehensive weighting factor of the intervals, which verifies the feasibility of the method. Based on this method, one of the key exploratory wells, Qiang21 in the Raoyang Sag of Bohai Bay basin, was selected as a case study and was determined to be a sweet spot interval of the shale oil reservoir in the upper third member of the Shahejie Formation. This study provides a new way to obtain a favorable exploration interval of shale oil reservoirs and serves shale oil development.

Logging evaluation of lamina structure and reservoir quality in shale oil reservoir of Fengcheng Formation in Mahu Sag, China

The Fengcheng Formation in the Mahu Sag of the Junggar Basin is composed of a set of fine-grained sedimentary rocks located under a layer of alkaline lacustrine rocks. There are alternating dolomite lamina, siltstone and organic matter laminae that show strong heterogeneity. The lamina structure determines reservoir quality and oil-bearing potential in shales. Therefore, the identification of lamina structure is a crucial basis for identifying reserves of shale oil. Identified as massive, layered and laminated, three different types of lamina structures are divided according to core observations in terms of the density of the laminae and the overlapping relationships. High-resolution processing is also performed on dynamic image log data to form slab images for recognizing the various types of lamina structures. Compared to core slab photos, it is believed that slab images offer an excellent thin-layer resolution of up to a millimeter in scale and can effectively identify the lamina structure of the shale reservoir. There are no evident beddings on the core of the massive pattern, and the slab image shows a bright or dark block pattern. There are centimeter-level felsic bands of fine silt sand on the thin-layered sedimentary fabric core, and the slice image shows a band-like pattern. A large number of millimeter-level dolomitic laminae are enriched on the core of the laminated type, and the slab image shows millimeter-level light and dark lamina. Slab images were used for the division and identification of lamina structures in a single well. Then, the relationships between the three types of lamina structures and the two-dimensional nuclear magnetic resonance logs and oil test data were recorded. The results show that massive and laminated pores are dominated by intergranular pores with low porosity and movable oil content. Therefore, only low oil flow can be obtained during an oil test. However, the layered type due to centimeter-level silty bands, T1 and T2, is bimodal with high porosity, movable oil content, and high levels of hydrocarbon production. Therefore, the optimal areas of shale reservoirs are closely related to the layered type. The more significant the proportion of layered types in shale reservoirs, the higher the quality of the reservoir. The present study is intended to identify lamina structure-controlled reservoir quality and oil accumulation and to provide insights into the exploration and development of shale oil.

Evaluation Method of Movable Shale Oil Resource: A Case Study of the Shahejie Formation in the Dongying Sag, Jiyang Depression

Although China has enormous shale oil resource potential, oil recovery is limited at present, largely because its movable resource is not evaluated. In this study, an evaluation method for movable shale oil resources is proposed. The process first evaluates the total shale oil resource (Qtotal), and then two-dimensional nuclear magnetic resonance (NMR) technology is used to measure the free oil ratio (Rfree) and further define the quantitative relationship (F) between the movable ratio (Rm) in the free oil and centrifugal force. The movable oil resource is calculated by the total shale oil resource, free oil ratio, and movable oil ratio (Qm = Qtotal × Rfree × Rm). This method was applied to the Shahejie Formation of the Dongying Sag, Jiyang Depression, in Bohai Bay Basin, and the relationship between the free oil ratio (Rfree) and depth was established based on several core 2D NMR data. Based on the formation pressure, flowing bottom hole pressure, and relationship (F), the movable shale oil ratio (Rm) in the target area was determined. The results showed that the movable shale oil ratio (Rm) of the lower Es3 is approximately 18.9–20% in the depth range of 3,200–3,700 m, and the movable shale oil resource is approximately 2.52 × 108 t.

Quantitative Method for Evaluating Shale Oil Resources Based on Movable Oil Content

The light hydrocarbon content ( S 1 ) of shale oil is lost in aboveground experimental measurements, which do not accurately reflect actual underground light hydrocarbon content and cannot meet the demands of resource quantity calculation. Based on field and laboratory experimental data from the second member of the Kongdian Formation in the Cangdong Sag, Bohai Bay Basin, the retained oil and movable oil contents in shale were calculated using a mathematical formula, and the total resources were quantified. The correction coefficient of S 1 from pyrolysis and the adsorption of oil by the total organic carbon (TOC) were determined to be 1.25 and 100 mg/g, respectively. The calculated parameter movable oil content ( S movable ) and the corresponding calculation formula of S 1 are proposed. The lower limit of S 1 is 100 mg HC/g rock, the TOC content is 4 wt % and 6 wt %, and the corrected movable oil content of 3 mg/g and 6 mg/g, respectively, will be of great significance in shale oil geology and engineering. The optimal geological and engineering settings are divided into three categories and eight subcategories on the basis of these findings. Methods for evaluating total, movable, and recoverable oil resources from shale are discussed, which elucidate a new method for quantitative evaluation and ranking of shale oil resources. This approach is suitable for application in other shale oil exploration and development areas globally.