Introduction
The continental shale oil resources are abundant in China [1]. It is estimated that the geological reserves of shale oil with vitrinite reflectance (Ro) exceeding 1.0 are 100×108 t, while those with Ro below 1.0 range between 700×108 t and 900×108 t. Notably, significant breakthroughs have been achieved in the exploration and development of shale oil [2⇓⇓⇓⇓⇓⇓⇓⇓-11], including the Perimian Lucaogou Formation in Jimusar Sag of Junggar Basin [2], the first member of Cretaceous Qingshankou Formation in Gulong Sag of Songliao Basin [3], the seventh member of Triassic Yanchang Formation in Ordos Basin [4], the second member of Paleogene Kongdian Formation in Cangdong Sag of Bohai Bay Basin [5], and the third to fourth members of the Eocene Shahejie Formation in Jiyang Depression of Bohai Bay Basin [6⇓⇓-9]. Shale oil has gradually emerged as a pivotal replacement resource in China's oil and gas industry. Initial estimates suggest that the resource potential of shale oil in Jiyang Depression exceeds 100×108 t, making it a standout example of continental shale oil in China.
The shale oil exploitation in Jiyang Depression has undergone four stages: exploration encounter, active exploration, innovative breakthrough, and evaluation and production [7⇓-9,11]. In 2019, Well F159 marked a significant breakthrough in production testing, followed by high-production results at Wells NX55 in Niuzhuang subsag, FYP1 in Boxing subsag, YYP1 and BYP5 in Bonan subsag. In April 2021, a successful 3D development well group pilot test was conducted at Well FYP1 area. The Shengli Jiyang Continental Fault Basin Shale Oil National Demonstration Zone was approved for construction in December of the same year. Furthermore, a comprehensive evaluation of shale oil was carried out in Niuzhuang and Minfeng subsags in 2022. As of December 2023, 112 horizontal wells had been deployed for Jiyang shale oil, with over 80 wells completed and 69 wells brought into production. Of the 69 wells, 22 wells had achieved daily oil production exceeding 100 t, highlighting the immense developmental potential and commercial value of shale oil in Jiyang Depression.
The concept of “volumetric development” has been established for marine shale oil in North America [12-13], while the development of continental shale oil in China is still in its infancy. Jiyang Depression, as a typical representative of continental fault basins, exhibits significant variations in source rock thickness, well-developed faults and fractures, rapid lithofacies changes, low maturity, high formation temperature and pressure, and complex geostress. It faces multiple challenges in “sweet spot” evaluation, overall utilization, production management, and efficient fracturing. While previous studies have mainly focused on the sedimentary characteristics, enrichment law, occurrence mechanism, and exploration practices of shale oil in Jiyang Depression [6,11,14⇓⇓ -17], there is a lack of research on the theory, technology, and practice of shale oil development in continental fault basins. There are no successful precedents, either domestically or internationally, on how to transform the breakthrough in single-well shale oil production into economically viable large-scale development. To address this gap, this paper presents the ternary-element storage and flow concept for continental shale oil based on the analysis of test data of more than 120 000 samples from over 12 000 m of rock cores taken from over 40 wells in different subsags of Jiyang Depression. The aim is to provide a valuable reference for the beneficial and sustainable development of continental shale oil and gas resources in China.
1. Overview of shale oil in Jiyang Depression
1.1. Geology
Jiyang Depression, located in the southeastern part of Bohai Bay Basin, can be divided into Dongying, Huimin, Zhanhua, and Chezhen Sags. It is dominated by two sets of hydrocarbon source rocks: the upper submember of the fourth member of the Eocene Shahejie Formation (also known as Es4U) and the lower submember of the third member of the Eocene Shahejie Formation (also known as Es3L). These source rocks are buried at depths ranging from 3 000 m to 5 500 m, with a stratigraphic thickness between 300 m and 1 500 m. They serve as the primary producing layers for shale oil in Jiyang Depression.
Jiyang Depression is a prime example of continental faulted lacustrine basins, typified by multiple half-graben sags with steep northern and gentle southern slopes. It experienced three Himalayan orogeny faulting events during the Paleogene shale sedimentary period. The intense tectonic activities and the overpressures induced by hydrocarbon generation led to well-developed multi-scale fractures in shales of Es3L and Es4U. Compared to marine shales in North America and continental shales in Ordos Basin, Songliao Basin, and Junggar Basin, the shales in Jiyang Depression are younger, with predominantly lime-rich or mixed lithofacies. For these shales, the Ro values range from 0.5% to 1.2%, and the resources of medium- and low-maturity shale oil with Ro less than 0.9% account for 66%. Moreover, the formation temperatures range from 130 °C to 200 °C and the pressure coefficient is 1.2-2.0. Key features include low maturity, deep burial, large thickness, high temperature, high pressure, and complex lithofacies, structures and fluid properties (Table 1 ).
Table 1. Characteristics of shale oil in Jiyang Depression and other areas in China |
| Area | Horizon | Basin type | Shale lithofacies | Stratigraphic thickness/m | Burial depth/m | Ro /% | Crude oil density/ (g•cm-3) | |
|---|---|---|---|---|---|---|---|---|
| Range | Producing or test | |||||||
| Jiyang Depression | The Eocene Shahejie Formation | Saline to semi-saline lacustrine basin | Muddy limestone, limy mudstone | 300-1 500 | 3 000-5 500 | 0.5-1.5 | 0.7-0.9 | 0.82-0.89 |
| Cangdong Sag | The 2nd member of Paleogene Kongdian Formation | Semi-saline to freshwater lacustrine basin | Dolomitic and felsic shales | 50-200 | 2 800-4 200 | 0.5-1.1 | 0.86-0.89 | |
| Songliao Basin | The Cretaceous | Freshwater lacustrine basin | Felsic shale | 106-149 | 1 600-2 700 | 0.5-1.7 | 1.0-1.4 | 0.78-0.87 |
| Ordos Basin | The 7th member of Triassic Yanchang Formation | Freshwater lacustrine basin | Siltstone, fine sandstone | 10-40 | 1 600-2 900 | 0.7-1.2 | 0.80-0.86 | |
| Junggar Basin | The Permian Lucaogou Formation | Saline lacustrine basin | Dolomitic siltstone, muddy dolomite | 20-70 | 2 500-4 800 | 0.6-1.1 | 0.88-0.92 | |
| Santanghu Basin | The Permian | Saline lacustrine basin | Muddy limestone, limy dolomite | 15-100 | 2 000-2 800 | 0.6-1.3 | 0.85-0.90 | |
1.2. Development
Since 2021, appraisal wells have been strategically deployed and drilled in five subsags: Boxing, Niuzhuang, Minfeng, Lijin, and Bonan. More than twenty wells, including FYP1 and FeY1-1HF, have achieved peak daily oil production surpassing 100 t. As of December 2023, 23 wells had accumulated over 10 000 t of oil production. On the basis of these well breakthroughs, 3D development pilot tests have been fully conducted. A pioneering 3D development pilot test was undertaken in Boxing subsag, involving drilling eight horizontal wells in three separate layers at Well FYP1 area. By September 2022, all eight wells had been put into production, with five of them reaching a peak daily oil production of over 100 t. The entire well group collectively reached a peak daily oil production capacity of 530 t, marking Sinopec's first successful establishment of a shale oil development well group capable of producing 100 000 t annually. Meanwhile, within Niuye 1 Block in Niuzhuang subsag, 20 wells have been strategically arranged for a 3D development project targeting five layers in the Upper Chunhuazhen Submember of the fourth member of the Eocene Shahejie Formation (Es4UC) and the Lower Submember of the third member of the Eocene Shahejie Formation (Es3L). All 20 wells have undergone hydraulic fracturing stimulation. Additionally, following the model of “holistic platform deployment and phased small well group implementation”, 39 appraisal pilot wells have been systematically deployed in Minfeng subsag. These deployments are currently progressing in an orderly fashion.
The decline law of shale oil production in Jiyang Depression exhibited similar characteristics to shale oil horizontal wells in Jimusaer and Daqing Gulong [18⇓-20]. The initial decline rate averaged between 56% and 70%, and initial oil production was typically observed within 2 d to 10 d of the horizontal well coming online. After one month of production, the water cut stabilized, and peak daily oil production ranged from 52 t to 263 t. The predicted ultimate recoverable reserves of a single well were estimated to be approximately (4.0-6.5)×104 t.
From 2021 to 2023, the shale oil development in Jiyang Depression achieved remarkable breakthroughs, transitioning from individual wells to well groups and evolving from 3D development in 3 layers to 5 layers. Daily oil production increased significantly from 100 t in early 2021 to over 1 400 t in late 2023. As a result, annual oil production exceeded 300 000 t in 2023.
1.3. Challenges
Although strides have been made in the evaluation and production of shale oil in Jiyang Depression, significant variations persist in the production capacity of horizontal wells in different subsags, with the underlying mechanisms for achieving high shale oil production remaining elusive. The efficient development of shale oil in Jiyang Depression faces the following challenges:
(1) The precise factors that govern the enrichment of low- and medium-maturity shale oil remain unclear. Shale oil in Jiyang Depression is characterized by low- to medium-maturity (0.5% to 1.2%), complex lithofacies, and well-developed multi-scale pores and fractures, and diverse types of storage spaces. The pore-fracture combination characteristics and the primary factors controlling shale oil enrichment and high production are yet to be fully understood.
(2) There is a limited understanding of fracturing stimulation and multi-scale flow patterns in fault basins. Fractures at various scales are prevalent in these basins, making it imperative to investigate how to achieve balanced expansion of induced fractures on the basis of natural fractures. The induced fractures are greatly variable in scales, and the intricate multi-phase and multi-scale flow patterns result in the unclear nature of oil/water flow paths.
(3) The mechanisms behind the high and stable production of shale oil horizontal wells need to be clarified. While the initial production from shale oil horizontal wells in Jiyang Depression is high, it declines rapidly. To fully capitalize on the original formation's high pressure, the use of fracturing fluids to boost energy, promote absorption, and minimize sensitivity needs to be further examined. This will allow for the rational release of formation energy, control production decline, maintain long-term stable production, and ultimately achieve maximum recoverable reserves.
2. The ternary-element storage and flow concept for shale oil in Jiyang Depression
In response to the intricate geological conditions of shale oil in the Jiyang Depression, a ternary-element storage and flow concept has been developed, involving the three key elements of “storage, fracture, and pressure”. This concept is grounded in foundational research and development practices, providing insights into the mechanisms of the enrichment and high production of shale oil in Jiyang Depression.
2.1. The “storage element” provides the material basis for the shale oil enrichment
2.1.1. Pore-fracture development characteristics govern the shale oil storage space
Pores. The lithofacies of shales in Jiyang Depression can be divided into two types: lime-rich, with a lime: felsic: clay mass ratio of 5:2:2, and mixed, with a lime: felsic: clay mas ratio of approximately 3:3:3. They correspond to different microscopic pore types. Numerous scanning electron microscope (SEM) images demonstrate that the shales in Es4U-Es3L primarily comprise micro-to nano- scale inorganic pores. These pores can be categorized into five types: calcite intercrystal pores, inter-granular pores, intracrystal pores, clay mineral interlamellar pores, and pyrite intercrystal pores (Fig. 1 ). Among these pores, calcite intercrystal pores are predominantly observed in lime-rich shales, with pore sizes of 50-1 000 nm. Intergranular pores are found in both mixed and lime-rich shales, exhibiting a wide distribution of pore sizes (10-2 000 nm), with a significant portion exceeding 50 nm, due to compaction and cementation effects. Intracrystal pores are small in size (mostly less than 50 nm) and exhibit limited connectivity, primarily resulting from calcite intracrystal dissolution or calcite crystal growth defects. Clay mineral interlamellar pores develop between clay mineral crystals and have small pore sizes (mostly less than 50 nm), with limited connectivity. Pyrite intercrystal pores are distributed within strawberry- shaped pyrite aggregates, exhibiting pore sizes ranging 2-100 nm and limited connectivity.
Fractures. The natural fractures within shales in Jiyang Depression can be classified as macrofractures and microfractures. Macrofractures primarily consist of millimeter- scale structural fractures, micrometer-scale overpressured fractures, and bedding fractures, which contribute greatly to permeability. The structural fractures exhibit lengths of 2-50 cm, widths of 0.1-1.0 cm, and a density of 3-5 fractures per meter. The overpressured fractures have lengths of 1-10 cm, widths of 0.01-2.00 mm, and a density of 0.2-1 fractures per meter. The bedding fractures can extend to several centimeters in length and have widths ranging from 1 μm to 10 μm. Microfractures primarily consist of micro- to nano-scale grain boundary fractures, intercrystal fractures, and organic matter shrinkage fractures, which significantly impact the reservoir properties. The grain boundary fractures are primarily observed in mixed-facies shales, with lengths ranging from 10 μm to 100 μm and widths from 0.1 μm to 2 μm. The intercrystal fractures are predominantly developed in lime-rich shales, exhibiting lengths of 10 μm to 200 μm and widths from 10 μm to 1 000 nm. The organic matter shrinkage fractures are concentrated at the margins of organic matter, with lengths and widths less than 1.0 μm, and are associated with the process of hydrocarbon generation and expulsion.
Fig. 1. Pore types and pore size distribution of shales in the Jiyang Depression. |
2.1.2. Pore-fracture combination modes govern the shale oil storage capacity
The formation, transformation, and preservation of pore-fracture combinations in shales are intricately linked to their fabric characteristics. Favorable rock fabrics are conducive to the development of pores/fractures and the occurrence and enrichment of hydrocarbons. Shales in Jiyang Depression primarily consist of endogenous and exogenous sediments, with the former deposited in chemical-biological sedimentation processes and the latter including clay- to silt-sized felsic minerals and clay minerals derived from terrigenous sources. The alternating climatic conditions between dry and wet seasons in a relatively deep and quiescent environment resulted in a distinctive laminated “lime-mud” texture. This texture is characterized by frequent alternation between lime lamina and mud lamina, with a small single-lamina thickness (0.1-0.5 mm) and a high lamina density (5 000-20 000 laminae per meter). During the diagenetic stage, the hydrocarbon generation and expulsion of organic matter transformed the laminated “lime-mud” texture, forming sparry lime laminae. Recrystallization produced sparry calcite grains, some of which could reach coarse crystal sizes and exhibited a horse tooth-like structure.
The cryptocrystalline/sparry lime laminae and mud laminae of the shale exhibit different types of pores/fractures due to variations in mineral composition and diagenetic transformations, resulting in distinct pore size ranges (Fig. 2 ). The cryptocrystalline lime laminae are characterized by calcite intercrystal pores, intracrystal pores, intergranular pores, and organic matter pores, with the calcite intercrystal pores being the most prevalent, which are large in quantity and size and exhibit good connectivity. The sparry lime laminae are extensively developed with intercrystal fractures that are mostly filled with asphalt, providing good porosity and permeability. The mud laminae are primarily composed of intergranular pores, clay mineral interlamellar pores, pyrite intercrystal pores, and a few grain boundary and organic matter pores. Intergranular pores and clay mineral interlamellar pores prevail. The connectivity of intergranular pores is closely linked to the microscopic fabric. When the felsic grains are large and enriched in layers, the connectivity is good; otherwise, the connectivity is poor when the felsic grains are small and dispersed. In summary, the pore-fracture combination of shales in Jiyang Depression, formed by the laminated lime-mud texture, is favorable for shale oil enrichment. The development of sparry lime laminae, in particular, significantly enhances the storage capacity.
Fig. 2. Characteristics of laminated lime-mud texture for shale oil development in Jiyang Depression. |
2.1.3. The hydrocarbon generation capacity and free hydrocarbon content determine the shale oil enrichment
The kerogen of shale oil in Jiyang Depression exhibits a remarkable hydrocarbon generation capacity. The shale oil source rocks in Jiyang Depression range in thickness between 300 m and 500 m, with a maximum of up to 1 500 m, and have the organic matter content typically exceeding 2.0% (up to 3%-6% in laminated lime-rich shales), with the Ro of 0.5%-1.2%. According to the theory of hydrocarbon generation in saline lacustrine basins [21], the kerogens of shale oil Jiyang Depression exhibit the characteristics of early maturity and early expulsion, with a relatively low maturity threshold for the peak of oil generation. Geochemical experiments on shales from Dongying Sag indicate that most kerogens of the shales in Es4U-Es3L are types I-II1. They have a hydrogen index of 555 mg/g for laminated textures, and the total content of free hydrocarbon and cracked hydrocarbon reaches 17.98 mg/g, indicating a strong hydrocarbon generation energy [22].
The laminated lime-mud texture and the prevalence of macropores of shales in Jiyang Depression contribute to a relatively high free hydrocarbon content (average 4.36 mg/g) in shale oil. Analysis of cores acquired by pressure coring indicates that the oil saturation ranges from 43.04% to 84.82%, with an average of 61.90%. Fluorescence thin sections reveal that the mud laminae in the shale are enriched with organic matters, such as fine algaes, which fluoresce in brown color, and the lime laminae contain a significant amount of light hydrocarbons in intercrystalline pores/fractures, fluorescing bright yellow. SEM images indicate that shale oil mainly exists as thin films and oil droplets within pores/fractures of different scales, and it precipitates at the margins of macropores and microfractures. This suggests that free oil primarily resides in macropores and microfractures.
2.2. The “fracture element” provides flow pathways for shale oil
The original pore-fracture system of shales in Jiyang Depression has a limited space to support the long-distance flow of shale oil. The reservoir is effectively “shattered” through large-scale fracturing to form a composite pore-fracture network system [23⇓-25], stimulating the opening of fractures such as bedding fractures, overpressured fractures, and structural fractures. This creates favorable flow conditions for high shale oil production.
2.2.1. Natural fractures control the shale oil migration and accumulation
Natural fractures are critical in shale oil enrichment and high production. Core observations reveal that the density, occurrence, and aperture of structural fractures are influenced by factors such as tectonic activity, geostress, and rock brittleness, and structural fractures are more prevalent in intricate fault zones. Overpressured fractures are related to laminated texture, organic matter abundance, and maturity. Structural fractures and overpressured fractures serve as favorable vertical migration pathways. For shales in Jiyang Depression, with well-developed bedding fractures, the overburden pressure testing demonstrates that the horizontal permeability is (0.009-1.020)×10−3 μm2, approximately two orders of magnitude greater than the vertical permeability which is (0.000 1-0.019 0)×10−3 μm2. The centrifugal NMR experiments further illustrate that shale with a well-developed laminated texture contains accessible pores as about 50% of the total pore space, whereas shale with an underdeveloped laminated texture features a proportion of accessible pores of only 20%-30%. This suggests that bedding fractures effectively connect isolated pores within the shale matrix, thereby enhancing the number of accessible pores and improving the lateral flow capacity of shale oil.
Bedding fractures play a crucial role in the migration and accumulation of shale oil. Microzone tests indicate that, in shales in Jiyang Depression, the mud laminae have the organic matter content of 8.11%-14.03%, the average free hydrocarbon content of 2.52 mg/g, the plane porosity of 0.4%-5.0%, and the permeability of (0.005- 0.010)×10−3 μm2. In contrast, the lime laminae have the organic matter content of 0.83%-4.39%, the average free hydrocarbon content of 5.66 mg/g, the plane porosity of 1.2%-11.0%, and the permeability of (0.1-1.0)×10-3 μm2. These parameters suggest that the mud laminae are highly capable of hydrocarbon generation but poor in storage, with heavy hydrocarbons primarily retained, whereas the lime laminae exhibit a poor hydrocarbon- generating capacity but robust storage capability. Both laminae facilitate the microscopic migration of free hydrocarbons through the bedding fractures and jointly control shale oil accumulation in Jiyang Depression.
2.2.2. Hydraulic fractures promote the high production of shale oil
The distribution of pore structure and the connectivity of pore-fractures dictate fluid distribution and flow patterns. During large-scale fracturing, the expansion of the artificial fracture network creates multi-level communication between pores and fractures on the nanoscale, micron scale, and main hydraulic fractures. This forms a multi-scale complex flow space. Analysis of unstable production shows that the average permeability within the horizontal well fracturing zone is 6.8 times that of the matrix permeability. Fracturing significantly improves the flow capacity of the treatment zone and enhances the flow passages of shale oil.
Given the unique laminated texture, pore-fracture combination, and fracture network distribution characteristics of shale oil formations in Jiyang Depression, a microflow simulation was conducted to model shale oil behavior. The results revealed that in the initial stage of shale oil development, the fracturing fluid and shale oil flowed back preferentially from the main fractures, the liquid was produced rapidly, and the fracturing fluid in the microfractures continuously imbibed to displace shale oil in the matrix pores. In the middle stage, pressure decrease in main fractures led to a rise in drawdown pressure, allowing the shale oil stored in the microfractures to be recovered. Moreover, due to the effect of imbibition, the water cut of produced liquid dropped noticeably and tended to stabilize. In the late stage, the pressure sweep and oil drainage radius gradually expanded, signifying the onset of the boundary-dominated flow stage. The percentage of shale oil produced from the matrix pores increased, the daily liquid and oil productions decreased gently, and the flow dynamics in the treatment zone stabilized gradually. As the formation pressure further dropped, the far-field fractures were gradually closed and ceased to serve as effective flow pathways, leading to a continuous reduction in the liquid supply range until production stopped at the wellhead.
2.3. The “pressure element” provides sufficient energy for the shale oil migration, accumulation and production
2.3.1. Primitive high pressures promote the shale oil migration and accumulation
Very thick freshwater lacustrine dark gray mudstones are present in the middle submember of the third member of the Eocene Shahejie Formation (Es3M), above the two sets of source rocks in Es4UC and Es3L. This set of mudstones serves as an effective seal for shale oil in Es4UC-Es3L. Abnormal high pressure is commonly observed within shales, indicating limited migration or dissipation of hydrocarbons generated by the source rocks. These favorable preservation conditions and enclosed environment enable the shales to hold sufficient original formation energy for the elastic development of shale oil.
The migration of free oil from mud laminae to lime laminae in the shales in Jiyang Depression was observed through SEM, confirming that the pressure induced by hydrocarbon generation provides the micro-migration force for hydrocarbons. Moreover, the lime laminae offers considerable storage space for hydrocarbons, while bedding and overpressured fractures serve as flow pathways. These factors, all together, facilitate the migration and accumulation of oil and gas.
2.3.2. Artificial high pressures increase the elastic energy
The experiments on rock pore volume compressibility indicate that the pore compressibility of shale can reach (0.3-0.9)×10-2 MPa-1 at atmospheric pressure, which is approximately three times that of tight sandstone ((0.1-0.33)×10-2 MPa-1). According to the reservoir engineering theory, the elastic production of shale oil is closely related to shale porosity, drawdown pressure, rock and fluid compressibility, and oil/gas/water saturation. During hydraulic fracturing, a large volume of fracturing fluid enters the formation, leading to an increased pore pressure and a substantial rise in the elastic energy of shale reservoirs. Additionally, during the fracturing process, CO2 injected comes into contact with crude oil, leading to the diffusion and dissolution of crude oil. The volume expansion coefficient of crude oil can increase by 53%, and the elastic energy can be further improved.
2.3.3. Artificial high pressures improve the imbibition capacity
The imbibition and displacement mechanism of oil- water two-phase fluids in micro- to nanoscale pore-fracture system is crucial for stable shale oil production. Wettability is the foundation for imbibition and displacement, while the capillary force in hydrophilic rocks acts as the imbibition force, effectively facilitating the imbibition and displacement process. The wettability of shale in different layers was tested using the NMR and imbibition displacement method. The results show that 12 out of 19 core samples are water-wet, and 4 samples are neutral. This confirms the relationship between shale wettability and the thermal maturity of organic matter: the lower the maturity, the more hydrophilic the rock is. The low-maturity environment of shale in Jiyang Depression has contributed to its overall hydrophilic nature, providing a favorable condition for shale oil displacement by spontaneous imbibition.
Artificially forced imbibition can significantly increase the pore pressure and the contact area of imbibition, further enhancing the rate and efficiency of imbibition displacement. Comparative experiments between atmospheric and high-pressure imbibition in different lithofacies demonstrate that the recoveries of cores in high-pressure imbibition are 3-6 percentage points higher than those achieved in atmospheric pressure imbibition (Fig. 3 ). This suggests that the fracturing fluid, along with the imbibition agent and the artificially induced high- pressure environment, facilitates the entry of fracturing fluid into the formation, thereby enhancing the efficiency of crude oil displacement.
Fig. 3. Imbibition recoveries in different lithofacies and at different pressures. |
2.3.4. Reasonable pressure control ensures long-term stable production of wells
Integrated fracturing simulation and numerical simulation reveal that, following a large-scale fracturing fluid injection, the formation pressure can increase by 7.3-12.6 MPa, the pressure coefficient can increase by 0.3-0.5, and the equivalent permeability of the treatment zone can increase by 5-8 times. Once the well is put into production, the stress on the proppant rises, leading to a gradual shrinkage of the effective fracture space. The speed of fracture closure is positively correlated to the speed of formation pressure decline. The faster the formation pressure drops, the sooner the fractures are closed. Therefore, it is crucial to maintain the stable long-term production of shale oil by reasonably controlling the pressure decline rate to ensure that the fractures remain effective for a longer duration.
2.4. Three elements jointly control shale oil the enrichment and high production
2.4.1. The synergy of three elements controls the high and stable production of shale oil
To achieve high production of shale oil wells, the collective support of the storage element, fracture element, and pressure element is essential, as none of these elements can be dispensed with (Fig. 4 ). The "storage element" represents the storage capacity, hydrocarbon generation capacity, and oil content of shale, and serves as the material basis for shale oil enrichment. Shale oil reservoirs are non-commercial if no robust material base is available due to insufficient hydrocarbon-generating capacity. The “fracture element” focuses on the flow pathways in shale oil reservoirs. Without a naturally complex pore-fracture system, a complex fracture network cannot be created through hydraulic fracturing, which will limit the contact area for oil-water displacement and thus lead to uncertainties in imbibition and displacement performance. The “pressure element” encompasses natural energy and artificial energy. In scenarios of poor preservation conditions and insufficient original formation pressure in shale oil reservoirs, even the artificial energy generated by specific treatments will escape rapidly. This may incur a series of problems, such as a limited effective imbibition-flow space, a high threshold of movable oil pore space, and insufficient energy for elastic development, which will impede the stable production.
Fig. 4. Triangle of ternary-element storage and flow concept for shale oil in Jiyang Depression. |
2.4.2. Development based on the ternary-element storage and flow concept
Based on the ternary-element storage and flow concept, an integrated whole-chain development concept, involving shale oil enrichment, hydraulic fracture expansion, enhanced high pressure energy, and pressure sensitivity control, is proposed for Jiyang Depression. Shale oil should be further evaluated in terms of source rock quality, lithofacies, porosity, oil content, mobility, and fracturability, using core, experimental, testing, logging, and seismic data, and then the favorable sweet spots be defined. Horizontal well trajectories and 3D well pattern should be optimized to cover favorable sweet spots for maximizing the recovery of reserves.
During fracturing stimulation, the matching relationship between the parameters, such as fracturing fluid formulation, liquid/proppant volume, and flow rate, the lithofacies and natural fractures should be thoroughly considered. The advantages of natural fractures should be leveraged, and the planar and vertical extension of induced fractures be controlled accurately, in order to determine rational well spacing and layer spacing. The fracturing parameters should be optimized to avoid engineering issues like stress concentration and casing deformation that may arise during fracturing operations, ultimately achieving a balanced 3D reservoir stimulation.
After fracturing stimulation, the soaking time should be managed reasonably to allow the adequate penetration of fracturing fluid into the reservoirs for efficient imbibition and displacement. During production, the nozzle size for specific development stage should be managed properly to maintain a sustained high-pressure level in the treatment zone, maximize flow space in the pores and fractures, and improve the utilization of elastic energy.
3. Techniques for 3D development of shale oil in Jiyang Depression
The 3D development of shale oil is a technology suitable for continental shale oil reservoirs, which are characterized by intricate lithofacies, diverse storage spaces, high heterogeneity, and thick source rocks. Specifically, based on precise evaluations of sweet spots, a vertical multi-layer 3D reservoir compartment is constructed artificially by using the engineering techniques such as fast drilling and volume fracturing. The reservoirs are adequately stimulated by the geology-engineering integration technique. Thus, the reservoirs, fractures and well pattern are aligned spatially through the efficient coordination of well, well group and platform and the optimized adjustment and control throughout the process of drilling, fracturing and production. This technology can be used to enhance the percentage of deployed reserves to maximize recovery and economic benefits. It includes three core techniques: 3D well pattern optimization, 3D balanced fracturing, and full-cycle optimization of adjustment and control
3.1. 3D well pattern optimization
3.1.1. Sweet spot evaluation and prediction
Differential logging interpretation models were established for key parameters such as lithofacies, porosity, organic matter content, free hydrocarbon content, and brittleness index by studying shale sedimentary environments and lithofacies combinations. A sweet spot classification and evaluation method was developed, with consideration to factors such as geological sweet spot, engineering sweet spot, fracturing risk, and development economics. A standardized composite column for shale oil, covering such factors as geological strata, lithofacies, “four properties” (porosity, oil content, mobility, and fracturability), and sweet spot classification was established for different subsags (Fig. 5 ) to clarify the vertical distribution of sweet spots further.
Fig. 5. Composite column for shale oil in Jiyang Depression. GR—Gammy ray; Rt—Formation resistivity; Rxo—Flushed zone formation resistivity; S1—Free hydrocarbon content; TOC—Total organic carbon content; ρ—Formation density; Δt—Acoustic time; ϕ—Formation porosity; ϕCNL—Neutron porosity. |
Based on high-precision seismic target processing, the vertical seismic profile (VSP) data was utilized to fine-tune the calibration of the seismic data, and a highly precise 3D velocity field was constructed. The structural interpretation error was maintained at less than 3‰, ensuring accurate targeting of the horizontal well trajectory. Seismic response templates were established for different lithofacies by simulating the seismic response characteristics of these lithofacies, leading to the development of a beneficial lithofacies assemblage prediction technique for seismic waveform clustering analysis. This resulted in a lithofacies prediction agreement rate exceeding 85% when compared with real-time drilling data.
3.1.2. Layer set division
By considering multiple factors such as resource abundance, stress barriers, favorable lithofacies thickness, brittleness index, longitudinal stress difference, natural fracture development, and thickness limitations for economic development, shale oil development layer sets were divided, and layer set models were established for 3D economic development in different subsags.
In Boxing subsag, the ratio of favorable lithofacies interval thickness to hydraulic fracture height ranges 3-4, barriers are relatively underdeveloped, and the longitudinal stress difference is 7-9 MPa. The correlation analysis between single-well investment and recoverable reserves reveals that, given a 2 000 m horizontal section and a single-well investment of 60 million yuan, the limit thickness of favorable lithofacies for economic development is 28 m. Given the current drilling and fracturing conditions, a 3-layer 3D development mode was determined for shale oil development in Boxing subsag. In Niuzhuang subsag, the ratio of favorable lithofacies interval thickness to hydraulic fracture height of 4-5, two sets of 2-5 m relatively stable mudstone barriers are development, the longitudinal stress difference falls within the 5-6 MPa range, and natural fractures are well-developed. The favorable lithofacies thickness varies from 300 m to 500 m, with an economic development limit thickness of 26 m. A 5-layer 3D development mode was determined to be suitable for shale oil development in Niuzhuang subsag. In the Minfeng subsag, which shares a similar layer set division for 3D development to Boxing and Niuzhuang subsags, the ratio of favorable lithofacies interval thickness to hydraulic fracture height of 5-11, five sets of relatively stable mudstone barriers with thickness ranging from 2 m to 7 m are developed, and the longitudinal stress difference varies between 6 MPa and 8 MPa. A comprehensive assessment indicates that a 7-layer 3D development mode is suitable for Minfeng subsag.
3.1.3. Optimization of 3D well pattern and well spacing
Based on the morphology of fracture network obtained from microseismic monitoring and taking into account the extension and flow patterns of induced fractures at different scales, a three-zone flow model was established. The three zones include: easy-flow zone, slow-flow zone, and stagnant-flow zone. The easy-flow zone, with propped fractures in dominance, contributes over 90% of the production. The slow-flow zone, with branch and natural fractures in dominance, contributes 5%-8% of the production. The stagnant-flow zone, which remains an untreated matrix, contributes less than 2% of the production. The area with the production contribution over 98% is defined as the ultimate drainage area. Thus, the ultimate drainage area includes the easy-flow zone and the slow-flow zone. Additionally, pressure interference must be taken into consideration for optimizing well spacing. The spacing between wells with no pressure interference is defined as the ultimate interference well spacing. Numerical simulations were carried out separately under three conditions (less than the ultimate interference well spacing, more than the ultimate interference well spacing and less than twice the ultimate drainage radius, and more than twice the ultimate drainage radius). The ultimate recoverable reserves of a single well under the three conditions are estimated to be 6.5×104, 9.6×104, and 8.2×104 t, respectively. Clearly, the development effect of the 3D well group is optimal when the reasonable spacing is greater than the ultimate interference well spacing and less than twice the ultimate drainage radius.
3.1.4. 3D well spacing pattern
In continental fault basins, well-developed fault systems and varying formation dips (5°-23°) limit the horizontal lengths of wells to be deployed in the fault blocks, which restricts the effective control and recovery of reserves. Therefore, optimizing the well spacing pattern is essential based on the characteristics of the oil reservoir.
(1) Horizontal well spacing pattern
For table shale sedimentary areas, the optimal well deployment for 3D development was determined by synergizing layer spacing, well spacing, and induced fracture network. For complex fault areas, three schemes of well deployment, i.e. layer-tracing well deployment, layer- crossing well deployment, and small-angle well deployment within a block, were proposed through a comprehensive study on lithofacies/sweet spot thickness, fault size, fault block spacing, and geostress direction to clarify the fault throw limit for cross-fault cross-layer well pattern, and establishing a relationship diagram among the angle between the horizontal well direction and the fault strike, the horizontal length, and SRV (Fig. 6 ).
Fig. 6. Schemes of horizontal well deployment in Well FYP1 area. |
(2) Vertically deviated well pattern in complex fault blocks
The vertically deviated well + ultra-large-scale fracturing technique was recommended for blocks with small faulted block area and infeasibility of horizontal well deployment. At Well L988-X7 targeting three sets of shale oil reservoirs: Es3L, Es4UC and Es4LC, a series of large volume, extensive, and intense multi-stage hydraulic fracturing stimulation tests were conducted. These involved five-stage vertical fracturing, with an average fluid volume of 9 328-13 064 m3 and an average proppant volume of 501-560 m3 per stage. After stimulation, the SRV was more than doubled or tripled, the hydraulic pressure dropped by 0.569 MPa per thousand cubic meters, and the initial production reached 40 t per day. This successful application provides a novel strategy for developing shale oil resources in complex faulted blocks.
3.2. 3D balanced fracturing
An innovative, geology-reservoir-process integrated 3D balanced fracturing technique based on “fracture element” was proposed for shale oil development in continental fault basins, to address the challenges, such as local stress concentration, negative fracturing interference, and casing damage, due to the dynamic spatial pressure and stress field imbalances that often occur during 3D fracturing operations.
3.2.1. Fracturing design
3D fracturing design is an iterative process involving comprehensive geological analysis, fracturing system optimization, and fracture flow evaluation. Based on the fracturing design principle of “one scheme for one well, and one strategy for one stage”, a comprehensive shale evaluation profile for a single well and a spatial prediction database of multi-attribute fractures were established to clarify the spatial distribution of geology-engineering sweet spots and evaluate the channeling risk associated with faults and fractures. As for fracturing system optimization, with the support of the pressure-stress coupling simulation technology, the spatial expansion of fractures under each fracturing scheme is clarified, the fracturing scale is optimized on a well-by-well basis, and the overall fracturing sequence of the entire well group is also optimized, in order to maximize the degree of stimulation. As for fracture flow evaluation, the open flow regime of the 3D well group is optimized, the spatial and temporal evolutions of pressure, stress, and flow within the 3D treatment zone are clarified, and measures are taken to mitigate the risks such as unbalanced production and significant variations in water cut associated with rapid local pressure drop and stress concentration, in order to maximize the ultimate recoverable reserves.
3.2.2. Optimization of parameters
Large-scale volume fracturing serves as the cornerstone for effectively producing shale oil. Fracturing parameters for individual wells and 3D well groups can be meticulously optimized to mitigate operational risks, thus achieving balanced fracturing stimulation. Firstly, a differentiated design is considered for stage/cluster length depending on lithofacies drilled by horizontal section, so that lithofacies interfaces can be avoided to minimize the risk of casing damage. Given variations in stress profiles, pressure profiles and natural fractures along the wellbore, the parameters such as liquid/proppant volume and flow rate are optimized to minimize the likelihood of induced natural fracture slippage during the fracturing process. This ensures balanced expansions of induced fractures. Secondly, when designing fracturing parameters, the reasonable fracturing fluid and proppant volumes, as well as flow rate per stage/cluster, are optimized for each well based on the fracturing process, which can help prevent casing damage and frac-hits due to well interference. The dynamic pressure response of the well group is continuously monitored in a real-time manner during fracturing operations, and the fracturing sequence and scale are adjusted in real-time to avoid systemic casing failure due to local high pressure and stress concentration. This ensures a balanced 3D stimulation of the shale reservoir.
3.3. Lifecycle optimization and control
A lifecycle optimization and control technology for shale oil development was developed based on the “pressure element” to leverage the natural formation and artificial energy for maintaining high pressure over a long term, enhancing imbibition efficiency, and minimizing stress sensitivity.
3.3.1. Soaking time optimization
It has been found that a suitable well soaking time after fracturing is beneficial for enhancing imbibition and well productivity for shale oil reservoirs in Jiyang Depression which exhibit clear imbibition effects. Spontaneous imbibition experiments on shale cores revealed peak imbibition and displacement efficiencies at around 8 d. Field practices further indicated that wellhead tubing pressure stabilized within 10-15 d of well soaking. Through a comprehensive analysis, the optimal soaking time for shale oil wells in Jiyang Depression is determined to be 10-15 d.
3.3.2. Backflow pressure drawdown optimization
Production pressure drawdown should be appropriately increased to initiate oil-phase flow during the initial backflow stage when the oil corresponds to a start-up pressure gradient.The start-up pressure gradients of muddy limestone shale, limy mudstone shale and lime-bearing mudstone shale are determined to be 2-12 MPa/m through the comprehensive analysis of core flow experiment data, lithofacies characteristics in fracturing stages, liquid production profiles, and initial oil pressure drawdown. As the number of bedding fractures increases, the start-up pressure gradient of muddy limestone shale decreases from 2 MPa/m to 0.1 MPa/m, while that of lime-bearing mudstone shale decreases from 12 MPa/m to 3 MPa/m. Practices suggest that appropriately increasing the production pressure drawdown during the early post-fracturing stage can overcome the start-up pressure gradient in the immediate vicinity of the wellbore, thereby promptly activating oil flow pathways and expediting early oil production.
3.3.3. Production pressure drawdown optimization
Hydraulic fractures serve as the primary flow pathways for the production of shale oil. Controlling the production pressure drawdown within reasonable limits can help mitigate stress sensitivity, minimize the volume loss rates of the fracture network, and maximize the fracture flow conductivity. The volume loss rate of the fracture network is calculated as the ratio of the current effective fracture volume to the initial fracture volume, which indicates the changes in flow space after fracturing. Production practices have shown that the daily loss of fracture volume exceeds 1% when the production pressure drawdown is 7-8 MPa due to the use of large nozzles (6-8 mm), with the elastic yield falling below 800 t/MPa, while the fracture volume is relatively stable when the production pressure drawdown is 2-3 MPa due to the use of small nozzles (3-4 mm), with an elastic yield exceeding 1 500 t/MPa and the single well's ultimate recoverable reserves increased by 10%.
4. Application of ternary-element storage and flow concept in development
Boxing subsag is located in the southwest of Dongying Sag, where the shale oil reservoirs are typified by complex fault blocks. These shale oil reservoirs develop many faults at various levels with small fault block spacing and exhibit significant variations in formation dips. Four Class I sweet spots (Es3L-3, C4, C5, C8) were systematically identified from enhanced geological information. A 3-layer, 9-well, 3D development well group was then deployed at Well FYP1 area within the Class I sweet spot zone (Fig. 7 ). This configuration features an average horizontal length of 2 176 m. Specifically, four development wells were deployed near Well FYP1 in C5 layer, at a planar well spacing of 400 m. Additionally, Well FY1-3HF was deployed in C8 layer, Well FY1-1HF in Es3L-3, and wells FY1-2HF and FY1-8HF as small-angle horizontal wells in C5. The last two wells boast an average horizontal length of 1 468 m and an angle of 15°-20° to the direction of the maximum horizontal principal stress.
Fig. 7. Well pattern in Well FYP1 area. |
Based on the geology-engineering integration and the well-specific stimulation design, a total of 252 fracturing stages were implemented in 8 new wells, with a cumulative fluid volume of 69.6×104 m3 (2 764 m3 per stage), proppant volume of 4.15×104 m3 (165 m3 per stage), and CO2 volume of 4.09×104 t. The average SRV per well reached 1 786×104 m3. Following enhanced treatments involving oriented perforation, multiple temporary plugging, fiber fracturing fluid sand-carrying, and self-suspension proppant, the small-angle horizontal wells achieved a SRV per well of approximately 65% of that of conventional wells, ensuring a satisfactory stimulation effect. Since September 2022, the 8 wells have been brought into production successively. Guided by the ternary-element storage and flow concept, the stepped pressure control production method was optimized, leading to peak daily oil production of over 50 t for individual wells, over 100 t for five wells, and a peak daily production rate of 530 t for the entire well group. Additionally, two cross-fault horizontal wells achieved an initial daily production of 39.8 t, peaking at 68 t daily, with a cumulative production exceeding 1.0×104 t over the past 12 months, indicating a promising development effect.
Despite the production breakthroughs achieved in the major subsags of Jiyang Depression, cost-effective large- scale development remains a challenge due to variations in lithofacies, reservoir properties, oil content, and water cuts. Key unresolved issues include well pattern design and complex fluid control for extremely thick (over 1 500 m) shale oil layers, well pattern deployment in well-developed fault zones, fast drilling under abnormal high-temperature and high-pressure conditions, risks of frac-hit and casing damage, and enhanced oil recovery (EOR). Further efforts are needed with respect to shale oil enrichment and high production concept, sweet spot evaluation, 3D development design optimization, and EOR technologies, so as to achieve large-scale and efficient development of shale oil in Jiyang Depression.
5. Conclusions
The Jiyang Depression is endowed with substantial shale oil resources, very thick source rocks in the basin's saline lacustrine environment, well-developed inorganic pores and bedding fractures, and favorable reservoir properties and preservation conditions, which are fundamental for achieving high shale oil production in the depression. It is feasible to amplify the formation energy and significantly enhance shale oil flow space and capacity by judiciously utilizing natural fractures and enhancing the intricacies and reserve control of artificial fractures through hydraulic fracturing. The synergy of intricate fractures and high pressures bolsters the efficiency of oil-water imbibition and displacement, leading to effective water cut reduction. Maximizing the advancements of high pressures through precise pressure management could diminish shale stress sensitivity and boost individual wells' recoverable reserves. The synergy of storage element, fracture element, and pressure element underpins the consistently high yield of shale oil in Jiyang Depression.
Based on the ternary-element storage and flow concept, a 3D development technology was formed, with the core techniques of 3D well pattern optimization, 3D balanced fracturing, and full-cycle optimization of adjustment and control. This technology effectively guides the production and provides a support to the large-scale beneficial development of shale oil in Jiyang Depression. To achieve large-scale and efficient development of shale oil, the concept of ternary-element storage and flow needs to be deeply understood. Strengthening the researches on geology-engineering integration technique and improving 3D development technology of shale oil will lay a solid foundation for theory and technology of continental shale oil efficient development.