Introduction
Medium and high maturity Gulong shale oil resources in Daqing oilfield, NW China are huge ((100-150)×108 t). In 2021, 12.68×108 t of predicted reserves were reported, and Gulong continental shale oil national demonstration area were set up [1]. At present, the development of the demonstration area has progressed rapidly, from single- well breakthrough to oil discovery in the whole area, and confirmed the reliability of the resources and the potential for scale development. Gulong shale oil is the most typical in-situ shale oil. Compared with other shale in marine or saline lacustrine basins inside and outside China, the shale reservoir is characterized by tight lithology (the particle size smaller than 0.003 9 mm), clay minerals as the main skeleton, and pure shale as the main body. The reservoir space is composed of nano-matrix pores, mainly 10-60 nm. The occurrence and phase of crude oil are complex. The density of micro- and nano-bedding fractures is 1000- 3000 pieces/m. And the multi-scale flow characteristics are obvious after volume fracturing stimulation. Compared with other shales, the Gulong shale has unique characteristics in terms of rock structure, fluid phase, transport and flow mechanisms (micro- and nano-pore and fracture system) [1⇓⇓-4]. However, there are no available theory, technology and development experience, so it is challenging to achieve effective development of Gulong shale oil.
Scholars have carried out a lot of research on the occurrence and producing mechanism of crude oil in interbedded and mixed shale, fluid seepage mechanism, three-dimensional deployment, and development technology, etc. [5⇓-7]. However, Gulong pure shale oil has its particularity, and the following four key problems need to be solved to realize efficient development: (1) Underground reservoir state, including reservoir physical properties, fluid phase, crude oil occurrence and mobility; (2) Development mechanism, including classification of crude oil reserves, production system, evaluation of technically/economically recoverable reserves; (3) Crude oil flow mechanism, including initial flowing pressure, flow regime and law; (4) Efficient recovery scheme, including development mothed, early energy supplement and EOR technology.
Based on the previous studies and laboratory experiments [8-9], this paper deeply analyzes the occurrence and phase of Gulong shale oil in confined space, elaborates the understanding of its development mechanism and flow law, establishes a recoverable reserves evaluation method and a multi-scale flow characterization model, discusses the feasibility of early energy supplement for enhancing the oil recovery, and puts forward the future research target for effective development of Gulong shale oil. All findings are theoretical and technical references for effective development of Gulong shale oil.
1. Production performance and the scientific issues in efficient development
Gulong shale oil reservoirs in the Songliao Basin are dominated by shale with particles less than 0.003 9 mm, in which the cumulative thickness of other lithology such as siltstone and carbonate rock is very small. The shale oil is typical continental pure shale oil. The structural evolution of the Gulong shale oil pay zone is complex, the sedimentary environment is diverse, and the heterogeneity of the reservoir and space is strong, making the development of shale oil difficult [1]. Based on the theory of continental oil generation, and with the transformation of exploration concepts and technological progress, significant strategic breakthroughs have been made to the exploration of Gulong shale oil [10]. Key exploration wells such as GYH 1, YY 1H, and GY 2HC have delivered high production and relatively stable oil flow, confirming that Gulong shale oil has good exploration and development potentials [2-3]. The horizontal section of Well GYH 1 is 1562 m long. It has been producing for 850 d, and the cumulative oil and gas equivalent has been nearly 14 000 t [1]. Compared to the exponential decline characteristics of shale oil in North America, and Qingcheng in Changqing Oilfield and Jimsar in Xinjiang in China, oil and gas produce together from Gulong shale oil wells, exhibiting a special feature as hyperbolic decline (Fig. 1 ). For example, 11 trial production wells such as GYH 1 show a low hyperbolic decline [11], with an initial annual decline rate of only 14.5%. Numerical simulation carried out by using an organic-inorganic dual porosity medium model and average pore diameter as 20 nm exactly simulated the production performance of Well GYH 1 and realized the strong coupling of rock mechanics-flow mechanics-thermodynamics, organic-inorganic dual porosity media, and nanometer pores.
Fig. 1. Continental shale oil production performance curve in typical wells. |
The basic research on the development of Gulong shale oil needs to clarify four key issues: (1) Crude oil occurrence state and media. It is necessary to solve scientific problems such as characterization of reservoir physical properties, fluid flow regime, occurrence and mobility in nano-scale pores, and engineering and technical problems such as 3D reservoir geological model, fluid phase, distribution and mobility of free and adsorbed oil in confined space [12-13]. (2) Geological and recoverable crude oil reserves. It is necessary to address scientific issues such as method and standard of reserve classification, artificial production mechanisms, and engineering and technical issues such as evaluation and classification of geological and technically recoverable reserves. (3) Crude oil flowing and being produced. It requires solving scientific problems such as initial flowing pressure, multi-scale flow regime in matrix pores, bedding fractures and artificial fractures, and engineering technical problems such as nano-scale simulation experimental technology and multi-scale fine numerical simulation technology [14]. (4) EOR. It requires solving scientific issues such as well locations and development models, mechanisms and methods for enhancing oil recovery, and engineering and technical issues such as 3D well network, optimization of fracturing stimulation, production system and reasonable production technology and policy.
2. Basic research progress
2.1. Shale oil occurrence and fluid phase behavior
2.1.1. Occurrence of reservoir fluid
The Gulong shale oil reservoir develops many nanopores and high-density shale bedding fractures. The nanopores are mainly 10-50 nm, and their shapes are mostly irregular. The nano-fractures are mainly 10-50 nm [3]. Numerous studies have shown that crude oil in pores and fractures forms an adsorption layer on the surface of the pore wall, and the occurrence is divided into adsorption phase and free phase [15⇓-17]. Based on the different wettability of organic and inorganic pores to oil and water, an oil/water self-imbibition experiment was designed to quantitatively distinguish the occurrence of crude oil based on the corresponding porosity measured by injecting different fluids. According to the analysis of 7 cores from wells GY 2HC and GY 3HC (Table 1 ), the average percent of adsorbed oil is 21.06%, and the average percent of free oil is 78.94%. Free oil occupies a large proportion of the pores, which lays a foundation for the availability of crude oil.
Table 1. Occurrence of Gulong shale oil in the Songliao Basin |
| Sample No. | Well | Helium porosity/% | Percent of adsorbed oil/% | Percent of free oil/% |
|---|---|---|---|---|
| 1 | GY 2HC | 7.79 | 24.50 | 75.50 |
| 2 | GY 3HC | 9.20 | 18.00 | 82.00 |
| 3 | GY 2HC | 12.10 | 17.67 | 82.33 |
| 4 | GY 2HC | 10.08 | 8.46 | 91.54 |
| 5 | GY 3HC | 5.05 | 37.80 | 62.20 |
| 6 | GY 3HC | 10.87 | 14.63 | 85.38 |
| 7 | GY 3HC | 8.64 | 26.39 | 73.61 |
2.1.2. Phase behavior under the influence of nanopores, formation temperature and pressure
Shale oil in the center area of the Gulong Sag represented by Well GYH 1 has a gas-to-oil ratio (GOR) up to 2000 m3/m3 at the beginning of development. With fluid production gradually increasing, the GOR is stable at 500 m3/m3 [18]. According to the PVT test conducted on the fluid components at wellhead, the formation fluid is identified as volatile oil. However, the pores and throats in the shale oil reservoir are small, and there is strong interaction between crude oil and pore wall to form nano-confinement effect [19]. To distinguish nano-confinement space, the pore which is less affected by nano-confinement effect is defined as a macropore. Fluid molecules are severely affected by pore walls and their free movement is limited. Studies have shown that when the ratio of pore size to fluid molecular size is less than 50, the nano-confinement effect is significant [20], which is embodied by the offset of the critical characteristic point of fluid in the nano-confined space. However, since it is difficult to sample at wellhead or bottom hole to represent the fluid composition and phase behavior in actual reservoir matrix pores, and there is no mature nano-space phase test and experimental technology at present, the fluid phase behavior in nano-porous media has gradually become a research focus and challenge.
In this paper, capillary pressure, adsorption, and nano- confinement effect are considered to modify the classical equation of state. The modified equation of state is used to characterize the phase equilibrium of fluid in nanopores, and the phase envelopes at different pore scales are depicted. Phase diagrams of confined fluids in nano-pores of 5-50 nm and bulk fluids in pores larger than 50 nm were plotted (Fig. 2 ).
Fig. 2. Phase behavior of fluid in different pores. |
As the temperature and pressure in Gulong shale oil formation (37 MPa, 135 °C) are very close to the critical point of bulk fluid, the pore size has a great influence on the phase behavior of crude oil, and the phase envelopes of fluid vary greatly at different pore sizes. The smaller the pore size, the lower the saturation pressure of the mixed fluid, the more inward the movement of the envelope and the more obvious the offset. The time and pressure points where two phases appear delay in small pores. During the pressure depletion development of Gulong shale oil, light hydrocarbon components flow preferentially with the decrease of pressure in the matrix and shale fractures, which results in dynamic changes of phase behavior in the matrix and changes of fluid occurrence state (Fig. 3 ).
Fig. 3. Dynamic phase behavior of crude oil in different pores. |
At the initial stage of backflow, the fluid in nano-pores is condensate gas with a strong driving ability, and the fluid in large pores is volatile in gas-liquid two phases, inducing a phenomenon of "gas carrying oil", namely, light hydrocarbon components carrying heavy components. With the development from initial stage to middle stage, light hydrocarbon components are produced, heavy hydrocarbon components are retained, formation fluid becomes heavier. Pressure-temperature phase diagram changes and offsets, fluids in nanopores become volatile oil, fluids in macropores become black oil, flow capacity becomes poor, and heavy components are retained. Production performance indicates that during the initial stage of producing oil from bedding fractures, the content of C1 component in the produced gas gradually increases, while the heavy hydrocarbon components are gradually retained. Subsequently, the proportion of C1 component decreases, indicating that the medium to heavy hydrocarbon components flow in gas phase from the matrix nanopores to the bedding fractures (single-phase gas flow). After the fluid in macropores begins to produce, the light hydrocarbon components are produced in gas phase, while the medium to heavy hydrocarbon components are produced in liquid phase (two-phase flow). The proportion of C1 component in gas phase further increases (Fig. 4 ).
Fig. 4. Change of produced light hydrocarbon composition from Well GYH 1. |
2.2. Crude oil flow, production mechanism and method
2.2.1. Mechanism of crude oil flow
The crude oil in the Gulong shale oil reservoir is mostly enriched in nanopores and shale bedding fractures. How to effectively utilize this portion of crude oil is the key to stable and high production. Based on indoor experiments and high-precision simulations, a multiphase and multi-scale flow model of Gulong shale oil has been built based on artificial and natural bedding fractures and matrix pores, to get production from the nano-scale shale oil reservoirs (Fig. 5 ).
Fig. 5. Flow regime of Gulong shale oil after fracturing (the lines in the Figure are flow lines). |
Gulong shale oil reservoirs have developed high- density bedding fractures (1000-3000 pieces/m). The bedding fractures have high permeability. In the early stage of backflow, the fluid in the bedding fractures is preferentially produced. As the pressure in the bedding fractures decreases, the fluid in the pores begins to flow into the fractures. With changes in pressure and pore space, a large amount of dissolved gas is released from the fluid, effectively supplementing local energy, and providing a driving force to fluid flow. The progressive flow model from matrix pores, to bedding fractures, and to artificial fractures can significantly shorten the fluid flow distance, and effectively reduce the flow resistance in a simple medium.
2.2.2. Production mechanism
Based on physical simulation experiments, it has been determined that the effective utilization of Gulong shale oil is mainly achieved by the synergistic effects of elastic energy of pressure difference and compaction, imbibition displacement, gas carrying, and dissolved gas flooding. By using high-speed centrifugation and nuclear magnetic resonance (NMR) measurement to simulate the fluid production driving by elastic energy, it's found that the fluid in shale bedding fractures and macropores is preferentially produced, and the initial mass transfer is mainly driven by the pressure difference of the fracture system (Fig. 6a ). At the same time, it cooperates with compaction to provide driving energy, and the contribution of elastic performance in the initial development stage accounts for 45% to 53%. The spontaneous imbibition and NMR experiment shows that imbibition occurs between nanopores and bedding fractures. Compared to the ability of elastic energy to exert force on pores, imbibition can significantly reduce the limit of the smallest pore with movable fluid (Fig. 6b ). In the process of gas carrying liquid, the movement of gas molecules is more intense at high GOR, which can effectively break the entanglement between medium and heavy molecules in nanopores. The molecular interaction between gas and crude oil helps to "pull" the migration of heavy molecules and improve the flow ability of crude oil (Fig. 6c ). Gas has a "liquid carrying" effect, which reduces the resistance of crude oil migration. As pressure decreases, crude oil undergoes a phase change and gradually becomes an oil-gas phase. Before gas precipitation, the force is pressure difference. After gas precipitation, the gas phase rapidly accumulates and expands, releasing elastic energy, and the volume expansion coefficient increases sharply.
Fig. 6. Flow regime of pore fluid in Gulong shale oil reservoir. |
In the development process of Gulong shale oil, there is a synergistic effect among various flow mechanisms. The release of dissolved gas further increases the elastic performance. However, with the release of a large amount of dissolved gas, light components in the crude oil are severely dispersed, and the mobility of the remaining heavy components is significantly reduced. At the same time, the reservoir pressure severely depletes, resulting in a large amount of oil to remain in the reservoir. Therefore, the timing and amount of gas precipitation, as well as the control of pressure, are key factors on stable production. At the same time, the content of light hydrocarbon components in Gulong shale oil is relatively high, indicating a good foundation for spontaneous production. However, it is necessary to carefully control the development system, make reasonable use of formation energy, and achieve comprehensive utilization of matrix pores, bedding fractures, and artificial fractures.
2.2.3. Development models
Platform horizontal wells, CO2 pre-fracturing and pressure-controlled production have been developed for developing Gulong shale oil. The fracturing measures mainly include reverse mixing construction, high-viscosity main fluid, large-sized proppants, CO2 pre-fracturing and less clusters per stage [22].
The control of high-quality reserves is crucial for getting high production. To drill in the effective reservoirs as long and thick as possible is a key factor. Effective stimulated reservoir volume and conductivity play a critical role in increasing the producing matrix micro- and nano-pores. Fracturing stimulation not only "opens" and connects nano-scale pores, and increases pore connectivity and effective porosity, but also effectively supports bedding fractures and reduces flow resistance. According to the actual production curve of Well GYH 1 after fracturing, the reservoir permeability is 0.16×10−3 μm2. After increasing pore size and connecting with natural fractures, the permeability of the stimulated reservoir is 7.30×10−3 μm2, indicating a significant improvement in seepage capacity. Fracturing also improves near-wellbore permeability and provides seepage channels for effective production of matrix crude oil. A long-term effective diversion capacity and reasonable production system can ensure the orderly release of energy and maintain stable production capacity. The clay skeleton in Gulong shale is highly compressive, and the porosity, permeability and induced fracture are very sensitive to stress. A full-life-cycle working system at controlled pressure has been established, which is divided into four stages: soaking well, drainage and oil breakthrough, peak production, and stable production. By maintaining a long-term flow capacity of oil and gas in the fracture network and orderly release of reservoir energy, the EUR of the volume fractured wells is predicted to increase by more than 20%.
Based on the actual production performance data of Well GYH 1, the pressure and pressure derivative double logarithmic curves (Fig. 7 ) show that the flow regime in the horizontal well that has been producing for a long time has successively experienced a bilinear flow in artificial fractures and bedding fractures, a linear flow in bedding fractures, a linear flow from matrix pores to bedding fractures, and a linear from the outside to the inside of simulated reservoir. Crude oil in the artificial fractures, bedding fractures and matrix pores have been produced successively. Among them, the contribution of the oil in matrix nanopores is the main reason for the hyperbolic decline of Gulong shale oil production.
Fig. 7 The double logarithmic curves of pressure and pressure derivative in Well GYH 1. |
2.3. EUR prediction methods
The traditional EUR decline prediction method requires the production mode of the well to be constant bottom hole pressure. Gulong shale oil is characterized by large pressure fluctuation, high content of light components and complex phase characteristics under formation conditions, so it is difficult to accurately predict the future production performance and recoverable reserves by using a single-phase decline model.
Coupling analysis of production and pressure can be realized by introducing oil production per unit flow pressure drop and material balance time, thus eliminating the influence of pressure change on decline characteristics. The specific expression is as follows:
${{\delta }_{\text{i}}}\left( t \right)\text{=}\frac{q}{{{p}_{\text{wfi}}}-{{p}_{\text{wf}}}}$
${{t}_{\text{e}}}\text{=}\frac{\int_{0}^{t}{q}\text{d}\tau }{{{q}_{t}}}$
Through Eq. (1) and Eq. (2), the production data under variable pressure can be converted into the corresponding production characteristics under constant pressure production. The Duong model [22] considering coupling pressure-production and crude oil degassing is improved to Eq. (3), so as to obtain a new decline model and predict EUR and recoverable reserves by using the modified decline analysis method.
$\delta \left( t \right)\text{=}{{\delta }_{\text{i}}}\left( t \right)\left[ t_{\text{e}}^{-m}{{\text{e}}^{\frac{a}{1-m}\left( t_{\text{e}}^{-m}-1 \right)}} \right]{{\left( \frac{{{K}_{\text{o-t}}}{{\mu }_{\text{o-s}}}}{{{K}_{\text{o-s}}}{{\mu }_{\text{o-t}}}} \right)}^{n}}$
On this basis, to further control the multiple solutions of EUR and recoverable reserves prediction, a model prediction method based on multi-curve historical fitting and inversion is constructed using the modified decline analysis method. By comprehensively fitting multiple curves to determine key parameters related to reservoir, fractures, and relative permeability, a numerical model of typical wells and well groups is constructed to predict future production. The results are validated in conjunction with the decline analysis method to improve the accuracy of EUR and recoverable reserves prediction for Gulong shale horizontal wells.
Taking horizontal well GL-A as a case (Fig. 8 ), and based on the early actual production performance data, the EUR of the well is predicted to be 2.1×104 t by using the decline analysis method considering pressure-production coupling and crude degassing. Using a traditional decline method which does not consider pressure change and oil degassing, the EUR of GL-A is only 1.2×104 t. After continuously tracking the production performance, the prediction accuracy is up to 95.9% by the improved decline analysis method, and the coincidence rate of predicted cumulative oil production is 21.4%. The predicted recovery of depletion development ranges from 9.1% to 10.3%, with an average of 9.6%, based on the EUR and geological reserves in the test area.
Fig. 8. Comparison of fitted and predicted results of Well GL-A. |
2.4. Multi-scale flow simulation
Gulong shale oil reservoirs develop bedding fractures, inorganic pores (primary intergranular pores and intra-granular pores) and organic pores, and show structural characteristics of multiple media. Among them, matrix pores are the main storage space, and can be divided into micro-pores and nano-pores according to the pore size. Bedding fractures and artificial fractures are main flow channels, and fluid flow exists between them. A multi- scale flow model uses a Multiple Interacting Continua (MINC) and an embedded discrete fracture model (EDFM) to characterize the multi-scale pore-fracture media including nano-pores, bedding fractures and artificial fractures, and the flow and mass transfer between different scales.
2.4.1. Mathematical model
Consider multiple media such as organic pores m1, intragranular pores m2, intergranular pores m3, natural fractures f1 and hydraulic fractures f2. Assuming that there is no effective fluid flow in organic pores m1, mass transfer is carried out with other media through adsorption/desorption or diffusion, and the apparent permeability is modified by nano- and micro-space flow mechanisms such as Knudsen diffusion, negative slip boundary layer, and high-speed non-Darcy effect [23].
Mass transfer between pores in different matrices is characterized by channeling factors:
${{\alpha }_{{{\text{m}}_{\text{1}}}\text{,}{{\text{m}}_{2}}}}={{\sigma }_{{{\text{m}}_{\text{1}}}\text{,}{{\text{m}}_{\text{2}}}}}{{K}^{*}}{{L}^{2}}$
${{K}^{*}}=\frac{{{K}_{{{\text{m}}_{\text{1}}}}}{{K}_{{{\text{m}}_{\text{2}}}}}}{{{K}_{{{\text{m}}_{\text{1}}}}}+{{K}_{{{\text{m}}_{\text{2}}}}}}$
Since it is difficult to directly calculate the effective permeability of different media, the macro permeability of different media can be calculated by using the scale upgrade method based on the pore detour and volume fraction of different media, according to the Kozeny-Carman formula [24].
Multi-scale fractures in shale reservoirs include primary hydraulic fractures, secondary hydraulic fractures, and shale bedding fractures. To improve the efficiency of flow simulation, shale bedding fractures and secondary hydraulic fractures are deemed to be equivalent media (f1), and primary hydraulic fractures are treated as embedded discrete fractures (f2).
For f1, the conductivity between equivalent fractures and matrix is calculated using a channeling factor:
${{T}_{\text{mf1}}}={{\sigma }_{\text{mf}}}{{K}_{\text{m}}}A$
For f2, a grid equivalent distance method is used to calculate the channeling between embedded fractures and whole fracture network:
${{T}_{\text{mf2}}}=\frac{{{A}_{\text{fm}}}K_{\text{fm}}^{\text{*}}}{d}$
Different from conventional embedded discrete fractures, this model not only needs to calculate the channeling conductivity between discrete fractures and matrix, but also needs to calculate the conductivity between f1, forming a multi-scale model composed of multi-scale media + embedded discrete fractures (Fig. 9 ). And a numerical simulator based on the conductivity connection table architecture can realize the flow numerical simulation.
Fig. 9. Schematic diagram of multi-scale model and mass transfer process of shale oil. |
2.4.2. Model validation
The No. 1 Gulong Shale Oil Demonstration Area is located in the Gulong Syncline Zone of the Gulong Sag. The average porosity of the shale organic pores and inorganic pores is 3.8% and 5.8%, respectively. Well GYH 1 adopts a small-stage and dense clusters process to fracture the reservoir, totally 138 clusters in 35 stages. Based on the interpretation of the induced fracture network, a multi-scale multi-flow model is established, which is 9100 m×7200 m. Other parameters are shown in Table 2 .
Table 2. Multiple parameters in No. 1 Gulong shale oil demonstration area |
| Parameter | Value | Parameter | Value | Parameter | Value |
|---|---|---|---|---|---|
| Average porosity of organic pores | 3.80% | Average permeability of organic pores | 0.001×10−3 μm2 | Average porosity of discrete fractures | 57.30% |
| Average porosity of intragranular pores | 1.30% | Average permeability of intra-granular pores | 0.12×10−3 μm2 | Average permeability of discrete fractures | 350 μm2 |
| Average porosity of intergranular pores | 4.50% | Average permeability of intergranular pores | 0.73×10−3 μm2 | Average opening of discrete fractures | 1.6×10−3 m |
| Average porosity of shale bedding fractures | 0.11% | Average permeability of shale bedding fractures | 1.50×10−3 μm2 | Density of shale bedding fractures | 1000 pieces/m |
Numerical simulation on a multi-scale flow model shows that Well GYH 1 produces oil after shutting in 40 days and blowing out 21 days at controlled pressure after fracturing operation. At present, the oil production is 12.1 t/d, and gas production is 5222 m3/d at a 6.32 mm choke. The backflow rate is 23.9%. The fitted oil production curve (Fig. 10 ) is 90% coincident with actual production data, indicating the reliability of the multi-scale flow model.
Fig. 10. Actual and simulated oil production of Well GYH 1. |
On this basis, taking the increase of reserve utilization and recovery as a decision-making index, break the limitation of "single-well engineering", consider single-well and regional development, and establish a collaborative optimization method of well spacing, effective fracture length and fracture network. According to different fracturing scales, analyze the changes of cumulative production and regional recovery with well spacing, determine a reasonable fracturing scale, and design a collaborative fracturing stimulation and fracture network scheme. Fig. 11 shows the post-production pressure distribution in No. 1 test Gulong shale oil well group predicted by numerical simulation. After producing 5 years, the pressure drop is large, and spreads a large area, indicating that the degree of reserve utilization is relatively high. Fig. 12 shows the average cumulative production per well and regional oil recovery predicted at different well spacings. (1) At a well spacing of 200 m, the overall utilization degree of the reserves is the highest, but the cumulative production per well is low. (2) When the well spacing is larger than 400 m, the cumulative production curve per well rises slowly, while the overall utilization degree decreases significantly. (3) At technical level, it is recommended that the reasonable well spacing is 350 to 400 m at the present fracturing scale.
Fig. 11. Post-production pressure distribution predicted by numerical simulation in No. 1 test Gulong shale oil well group. |
Fig. 12. Predicted average single-well cumulative production and regional recovery at different well spacings in No. 1 test Gulong shale oil well group. |
3. Early energy supplement
The shale oil in North America experienced moderate thermal evolution and has high GOR, low crude oil viscosity and good fluidity. Oil and gas are produced together, which is one of the key factors for high single-well EUR. Compared with North American shale oil, Gulong shale oil has the characteristics of low GOR and small pressure difference at formation and saturated state. With depletion development, dissolved gas is released when the bottom hole pressure is lower than the bubble point pressure, and the mobility of crude oil becomes worse after many light components are recovered. In addition, a large number of bedding fractures are closed with pressure drop, and medium and heavy components are retained in reservoir and difficult to recover. The overall recovery of shale oil is low. Even if later energy supplement is carried out by injecting gas, after light components reduce, it is difficult for the injected gas to fully play the role of enhancing the recovery. In addition, because the bedding fractures serving as flow channels are closed, whether energy can be effectively supplemented is unknown, and the purpose for greatly enhancing the recovery is difficult to realize. Therefore, early energy supplement is very important to improve the development effect and recovery of Gulong shale oil.
At present, CO2 and CH4 are common gas injected into shale oil reservoirs to enhance EOR at home and abroad [25]. On the one hand, CO2 is the first choice because of its high oil displacement efficiency, low miscibility pressure, and a large expansion and diffusion coefficient. On the other hand, pre-CO2 fracturing practice shows that the flowback rate of CO2 is expected to be lower than 20%, and the storage rate is high. Therefore, to develop Gulong shale oil, it is better to change the passive idea of first deletion development and then energy supplement, to early energy supplement, especially injecting CO2 for energy supplement is expected to be the best way to enhance oil recovery while storing CO2 underground in developing Gulong shale oil.
3.1. Early CO2 huff-n-puff for energy supplement
3.1.1. Mechanism of CO2 huff-n-puff
The contribution of different mechanisms to enhanced oil recovery during CO2 injection in developing Gulong shale oil is quantitatively evaluated by means of high-temperature and high-pressure microfluidic visualization experiment, molecular dynamics simulation and CO2/crude oil competitive adsorption experiment. CO2 injection plays a leading role in dissolution and miscibility in matrix pores, which contributes the most to the cumulative production of shale oil, accounting for 42%. Elastic energy also plays a significant role in increasing the cumulative production, accounting for 30%. Elastic energy in the fracture system contributes the most to the cumulative shale oil production, which is 44% (Table 3 ). Therefore, CO2 huff and puff technology should be used to determine reasonable injection-production parameters for gas injection development from the perspective of forming miscible phases and increasing elastic energy.
Table 3. Contribution of CO2 EOR mechanisms in different media |
| EOR mechanism | Contribution proportion/% | |
|---|---|---|
| Matrix pore | Fracture | |
| Miscible effect | 42 | 27 |
| Elastic energy | 30 | 44 |
| Competitive adsorption | 18 | 13 |
| Molecular diffusion | 10 | 16 |
3.1.2. Early CO2 huff-n-puff
According to the characteristics of Gulong shale oil, which is highly stress-sensitive and irreversible, early CO2 huff and puff is carried out to supplement energy. This huff and puff operation is asynchronous. In other words, according to the fracture scale and network connectivity, gas is injected into the middle well while the two wells on both sides are soaked. Then the three wells are opened at the same time to produce. This can simultaneously play the role of supplying energy to the well to which gas is injected and displacing oil in the adjacent wells. To reduce the risk of gas channeling in large-scale fracturing stimulation, asynchronous water and CO2 injection is conducted, during which water may act as an artificial wall for preventing gas channeling while increasing energy (Fig. 13 ).
Fig. 13. Asynchronous water and CO2 injection to prevent gas channeling in developing Gulong shale oil. |
3.2. Well pattern for early CO2 injection
Gulong shale oil has low miscible pressure and strong swelling ability, indicating an excellent technical adaptability. The displacement experiments on samples show that the average movable fluid saturation reaches 47.61%. Two well patterns are considered. One is a "five-spot" well pattern which takes directional wells for gas injection and horizontal wells for oil production. It is beneficial to dynamic regulation and three-dimensional displacement (Fig. 14a ). The other takes horizontal wells as injection and production wells. The trajectory of the gas injection well is parallel to the orientation of induced fractures, the perforation is long, and the sweep scope is large (Fig. 14b ). Gas channeling can be effectively delayed by injecting gas at high reservoir points while producing oil at low reservoir point. Considering the overlap effect of gas injection, it is suggested to locate the trajectory of the production well at the 2/3 in terms of the reservoir thickness, away from the shale top (middle to lower part of the target layer), and finely adjust it according to the sweet spot distribution. On the premise of controlling well pattern and basic production system, the two gas flooding well patterns are compared with post-fracturing depletion development and energy supplement and pressure control development of horizontal wells. The injection-production well pattern, gas injection mode and injection-production parameters are optimized through numerical simulation. It's found the well pattern with directional wells for gas injection and horizontal wells for production is the most effective, and the recovery is expected to be 30% (Fig. 15 ).
Fig. 14. Comparison of development effects of two gas flooding well patterns. |
Fig. 15. Prediction results of gas injection development and post-fracturing depletion development of Gulong shale oil. |
4. Future research
Effective large-scale development of Gulong shale oil requires systematic theory and technology, and field tests and experiments to verify them. Then development methods are established and advanced, and finally become replicable and promotable development models. Based on the understanding of the particularity of Gulong continental shale oil and the analysis of scientific and technological issues, it is believed that key theory and technology for the effective development of Gulong shale oil need to focus on six aspects.
4.1. In-situ core and fluid sampling and non-destructive testing technology
In-situ sampling and non-destructive testing are necessary for obtaining the original properties of shale oil, which are vital for evaluation and efficient development of shale oil. At present, underground sampling, ground transferring sample and ground preparing sample are common to test core and fluid properties. However, difficult in-situ sampling, poor representativeness of ground sample preparation, and property changes caused during transferring samples (it is difficult to directly test the core in a steel sampling tube) make it is difficult to accurately understand and describe the original state and properties of the underground fluid, which directly affects the successive research and results. It is necessary to focus on developing in-situ sampling tools and methods to maintain formation conditions, and sampling cylinders and instruments to achieve non-destructive test. Positive progress has been made in high-precision mobile multi-dimensional full-diameter-sample NMR measurement system. It is necessary to accelerate the research and development of supporting methods and technologies, and an underground in-situ laboratory is expected to build.
4.2. HTHP nano-scale laboratory simulation experiment methods
At present, nano-scale simulation experiment at formation temperature and pressure has not been achieved. It is urgent to establish visualized experimental system and method for investigating the fluid occurrence, phase behavior, and flow regime under high temperature, high pressure, and nano-scale conditions. It could increase the ability to simulate real underground pore fluids, correctly understand the storage space, fluid state and flow regime at formation temperature and pressure, and exactly evaluate the mobility and recoverability of shale oil under formation conditions.
4.3. Multi-scale and multi-flow-regime numerical simulation technology and application software
Gulong shale oil may flow in various spaces such as organic pores, inorganic pores, bedding fractures, artificial fractures, and horizontal wellbore. There are different flow regimes in matrix pores, lamellations and artificial fractures. At present, no mathematical model and supporting software are available. It is necessary to understand the multi-scale mass transfer mechanism, establish multi-scale characterization model and method, and develop effective grid and solution technologies and application software, to provide reliable simulation means for development mechanism research and scheme optimization.
4.4. Anhydrous (CO2) fracturing and increasing vertical fracture height technologies
Shale oil reservoirs are tight, so artificial fracturing stimulation can improve the flow conditions and increase the EUR. No water is found in Gulong shale oil reservoirs. If injecting water to fracture the reservoir, water may change the original oil and gas phases to complex oil, gas and water phases, and seriously affect the recovery. Therefore, it is expected that an anhydrous fracturing system can greatly improve the EUR of Gulong shale oil. Studies should focus on anhydrous fracturing mechanism (e.g. CO2), developing anhydrous fracturing technical system and optimizing anhydrous fracturing parameters.
Vertical fracturing stimulation may induce a fracture network like a Chinese character "丰", but the fracture height is limited due to the widely developed horizontal bedding fractures in Gulong shale oil reservoirs. If higher vertical fractures can be induced, more horizontal bedding fractures could be connected. This can greatly improve the effectiveness of reservoir stimulation and development. It is monitored that the height of the supported fracture is generally less than 10 m in Well GY 1. Injecting fracturing fluid at a thousand cubic meters scale stimulated the reservoir that is only 40% of the volume of a tight oil reservoir at the same fracturing parameters. The current fracturing technology is far from meeting the production demand, so it is urgent to explore effective fracturing methods and technologies to increase the vertical fracture height.
4.5. Early energy supplement
Bedding fractures are developed in Gulong shale oil reservoirs, but they may close with rapid pressure drop. Once the fractures close, they won't open again, even if replenishing energy in the later development stage. So early energy supplement is vital. Studies should focus on large-scale CO2 pre-fracturing and refracturing, early CO2 huff and puff, chemical immersion and absorption, especially exploring the feasibility of CO2 flooding well patterns to enhance the recovery by over 30%. Early energy supplement is the best way to significantly enhance shale oil recovery.
4.6. Full-life-cycle technical and economic evaluation
Full-life-cycle technical and economic evaluation is an evaluation system that the overall investment, cost and output are considered in the entire life cycle of a construction project from its inception to its end. Furthermore, the full-life-cycle plan is optimized to minimize the cost and create the highest value through scientific design. Gulong shale oil has its unique characteristics compared with other shale oil, which is necessary to establish and implement an evaluation model and system for the entire life cycle. It is necessary to study the optimal relationship between investment and development/well pattern, horizontal well section length, fracturing scale, single-well production capacity and EUR, regional recovery and other influencing factors, establish technical benefit standard charts, establish investment standards for different zones and types, and improve standardized technical templates and development models, to guide high-quality, efficient, and high-level development throughout the entire life cycle.
5. Conclusions
There is an enormous potential and broad development prospects in Gulong shale oil resources in the Songliao Basin, but the particularity and complexity pose significant challenges for effective development. This paper focuses on the key issues related to the development of Gulong shale oil. Starting from basic research and combining with production and development dynamics, the underground occurrence, fluid phase behavior, producing mechanism, recoverability, flow regime, development methods, and early energy supplement are systematically investigated. Issues in four aspects are preliminarily clarified, including the underground occurrence, producing mechanism, flow regimes and efficient development method of Gulong shale oil. Future research directions and suggestions for field test are proposed to provide theoretical and technical references for the efficient development and production of Gulong shale oil.
Through systematic research, it's clear that fluid in Gulong shale oil reservoirs is composed of free fluid (relatively more) and adsorbed fluid (relatively less). The fluid phase characteristics are analyzed, the fluid phase diagrams under the confining effect of nanopores are provided, and the complex phase behaviors with oil and gas production are revealed. The multiphase and multi-scale flow regimes in matrix pores, artificial fractures and bedding fractures are understood, and the producing mechanisms are clarified, including differential pressure, seepage displacement, gas carrying, and dissolved gas driving. A prediction and evaluation method is established, which greatly improves the accuracy of single-well recoverable reserves prediction through coupling analysis of production and pressure decline, and multi-curve historical fitting and inversion. A multi-scale mass transfer/flow mathematical model is established by considering intergranular pores, intragranular pores, organic pores, shale bedding fractures, and artificial fractures. Reasonable well spacing and other parameters are simulated and studied. The feasibility of various early energy supplement methods is explored, including large-scale CO2 pre-fracturing and re-fracturing, early CO2 huff and puff, chemical immersion infiltration, and CO2 flooding well pattern. Early energy supplement is an effective way to significantly improve oil recovery. Finally, proposals are focused on 6 aspects related to theoretical and technical research, and field tests, with the intent to establish standardized technical and development methods for efficient development and large-scale production of Gulong shale oil.
Acknowledgement
In preparation of the paper, thanks to the National Natural Science Foundation of China "Research on Gulong Shale Oil Development Percolation Theory and Enhanced Oil Recovery Mechanism (U22B2075)" and the "Research on Gulong Shale Oil Phase Behavior, Percolation Mechanism and Geological Engineering Integrated Stimulation and Reconstruction" for fund support; and experts and scientific researchers from Daqing Shale Oil Exploration and Development Headquarters, Exploration and Development Research Institute and other institutions for supporting data, research and consultation.
Nomenclature
a, m—decline coefficient, dimensionless;
A—effective area of fractures, m2;
Afm—polygonal area of fractures embedded in matrix grid, m2;
d—equivalent distance between matrix grid and discrete fracture, m;
Di—initial decline rate, dimensionless;
$K_{\text{fm}}^{\text{*}}$—harmonic average permeability between fractures and equivalent media, 10−3 μm2;
K*—macroscale permeability, 10−3 μm2;
Km—matrix permeability, 10−3 μm2;
Km1, Km2—equivalent medium permeability, 10−3 μm2;
Ko-t—effective permeability of oil phase after degassing, 10−3 μm2;
Ko-s—effective permeability of oil phase before degassing, 10−3 μm2;
pwf—bottom hole flowing pressure, MPa;
pwD—dimensionless bottom hole flowing pressure;
pwfi—initial bottom hole flowing pressure, MPa;
L—mesoscopic characterization of unit body characteristic length, m;
n—correction coefficient for crude oil degassing, dimensionless;
n—fracture plane normal vector, m;
q—daily oil production, t;
qi—initial daily oil production, t;
qt—daily oil production at t, t;
S—unit area of fractures, m2;
s—slope of log-log pressure derivative curve, dimensionless;
t—production decline time, d;
tD—dimensionless time;
te—material balance time, dimensionless;
Tmf1—equivalent fracture medium and matrix conductivity, 10−3 μm2;
Tmf2—channeling between fractures and multi-media, 10−3 μm2;
x—directional vector from fracture center to end point, m;
αm1,m2—channeling factor between organic pores and intragranular pores, 10−3 μm2•m2;
δ—oil production per unit flowing pressure drop, t/MPa;
δi—initial oil recovery per unit flowing pressure drop, t/MPa;
μo-t—viscosity of crude oil after degassing, mPa•s;
μo-s—viscosity of crude oil before degassing, mPa•s;
σm1,m2—heterogeneity coefficient between organic pores and intragranular pores;
σmf—cross-medium channeling factor, m−1.