Introduction
Shale oil and gas refer to the oil and gas resources that are enriched in the organic-rich shale[1,2,3]. The shale oil and gas revolution in the United States has changed the world energy production landscape[4,5,6,7,8,9]. In 2018, the shale oil production in the United States reached 3.29×108 t[10]. China is rich in shale oil resources[1-3, 11-12]. The United States Energy Administration estimated that the technically recoverable shale oil resources in China was next only to Russia and the United States, ranking the third in the world[2], among which the recoverable shale oil resources in mud-shale dominated formations in the continental lake basins were up to (30-60) ×108 t. In recent years, progress has been made in the shale oil development test zones such as the Jimusar sag in the Junggar Basin, Xinjiang, Triassic Chang7 Member in the Ordos Basin, Qingshankou Formation/Yaojia Formation/Nen1 Member in the Songliao Basin, Cangdong sag in the Bohai Basin, and Qianjiang sag in the Jianghan Basin[13,14,15,16,17,18,19]. Shale oil is expected to become an important replacement field of petroleum exploration and development in China.
The inter-salt shale oil in Qianjiang sag of the Jianghan Basin is a typical type of shale oil in China. The Qianjiang sag is the most important salt-forming center in the Jianghan Basin and also a large hydrocarbon rich sag in this area[20,21]. The overlying and underlying layers of the inter-salt shale oil reservoir in Qianjiang sag are two sets of salt rocks, mainly including glauberite, dolomite, argillaceous dolomite and dolomitic mudstone[22,23]. During the drilling of shale oil in this area, 128 wells had oil and gas shows detected at the wellheads. At present, one development test zone has been established and 14 wells were put into operation in the early stage, with a cumulative oil production of 4.2×104 t[24]. One of the important characteristics of the inter-salt shale oil reservoir is the high content of soluble salts (mainly Na2SO4·CaSO4). With the progress of waterflooding, the salts can be decomposed into highly soluble Na2SO4 and slightly soluble CaSO4 under the action of water, thus promoting the conversion of the space occupied by solid salts into pore space, namely, salt dissolution occurs. This salt dissolution related to the soluble salt content and the pore throat structure is very important for the effective development of inter-salt shale oil[24]. The mechanism of salt dissolution of inter-salt shale oil should be studied and quantitatively characterized. With the inter-salt shale oil reservoir in the Jianghan Basin as an example, the salt dissolution of inter-salt shale oil cores and its effect on spontaneous imbibition and permeability are studied by means of salt dissolution experiment, imbibition experiment and HTHP NMR online tests.
1. Experiments
1.1. Salt dissolution experiment
Oil-bearing cores of inter-salt shale were used to carry out salt dissolution experiment to evaluate the salt dissolution intensity with NMR. Two oil-bearing cores of inter-salt shale were taken from Qianjiang sag in the Jianghan Basin to carry out the salt dissolution experiment. The basic physical parameters of the cores are shown in Table 1. The experimental steps are as follows: First, an organic solvent was used to wash the crude oil in the shale and then the shale core was dried, vacuumized and saturated with simulated formation water with a salinity of 300 g/L under pressure (the simulated formation water was consistent with that of the actual formation water in salinity and was prepared according to salt components from the analytical results of actual formation water). NMR T2 spectrum of the core was tested after saturated with water; then the core was suspended in a beaker with the injected water. To prevent the influence of clay swelling on the experimental results, the simulated formation water with a salinity of 50 g/L was selected as the injected water in the salt dissolution experiment. At different time points (0.5, 1.0, 2.0, 4.0, 7.0, 10.0, 23.0, 31.0, 52.0 h and 3, 8, 18, 25, 50 d), the core was taken out and wiped off the surface water to carry out NMR T2 spectral test. In the whole process of this experiment, water was the only fluid medium, so there was only salt dissolution but no imbibition. In order to ensure the comparability of test results in different stages, a standard sample test was conducted before each NMR test to eliminate the influence of NMR signal deviation on the experiment.
Table 1 Basic physical parameters of oil-bearing cores of inter-salt shale in salt dissolution experiment.
| Core No. | Lithology | Permeability/ 10-3 μm2 | Porosity/ % | Length/ cm | Diameter/ cm |
|---|---|---|---|---|---|
| 1 | Argillaceous dolomite | 0.17 | 10.580 | 5.462 | 2.50 |
| 2 | Argillaceous glauberite | 0.23 | 2.996 | 4.966 | 2.50 |
1.2. Imbibition experiment
Due to the presence of bedding and fractures and salt in shale, imbibition and salt dissolution would occur simultaneously in the process of water flooding development of inter-salt shale oil reservoirs, but the mechanism of their interaction is still unclear. In this work, two other oil- bearing inter-salt shale cores were selected to study the interactive mechanism of imbibition and salt dissolution. The basic physical parameters of the cores are shown in Table 2.
Table 2 Basic physical parameters of oil-bearing cores of inter-salt shale in imbibition experiment.
| Core No. | Lithology | Length/ cm | Diameter/ cm | Porosity/ % | Permeability/ 10-3 μm2 |
|---|---|---|---|---|---|
| 3 | Argillaceous dolomite | 5.251 | 2.50 | 7.83 | 0.21 |
| 4 | Dolomitic mudstone | 5.707 | 2.50 | 9.22 | 1.82 |
The experimental steps are as follows: The cores were washed with an organic solvent to remove oil and then dried, vacuumized and saturated with kerosene, then the NMR T2 spectra of the cores completely saturated with kerosene were tested; the cores were hung in a beaker filled with deuterium water 50 g/L in salinity (there is no signal of deuterium water in NMR tests) to allow spontaneous imbibition in the cores. The cores were taken out at different time points (0.5, 1.0, 2.0, 4.0, 7.0, 10.0, 23.0, 31.0, 52.0 h and 3, 8, 18, 25, 50 d), wiped off the surface water and test NMR T2 spectra, finally the total recovery percent of reserves and salt dissolution rate of them were calculated according to the test results.
1.3. HTHP NMR online test
An online HTHP NMR testing system has been developed by combining the low field NMR testing technology with the HTHP displacement physical modeling experiment of core (Fig. 1). The system has the following characteristics: (1) A HTHP probe is developed for NMR tests, the experimental confining pressure can reach 40 MPa and the temperature 80 °C. (2) The shortest echo time is shortened to 0.1 ms, which is capable of detecting the fluid signal in the Nano-scale pore throats. (3) The NMR heat cycling unit and pressure pipeline are modified to allow simulation of HTHP formation conditions. (4) The stratified T2 spectrum and MRI technology for cores are formed, which can be used to accurately observe the fluid saturation changes in the pores of different axial cross sections in the displacement or imbibition process.
Fig. 1.
Fig. 1.
HTHP NMR online test system.
The NMR on-line dynamic tests were carried out on two oil-bearing shale cores with the system to evaluate the salt dissolution of the oil-bearing shale cores and its impact on the seepage flow in the development process. In this experiment, the cores do not need to be taken out and the NMR tests can be carried out directly, avoiding experimental test errors caused by the change of system stress and repeated placement of the cores after taken out. The basic physical parameters of the two cores are shown in Table 3.
Table 3 Basic physical parameters of oil-bearing cores of inter-salt shale in HTHP NMR online test.
| Core No. | Lithology | Permeability/ 10-3 μm2 | Porosity/ % | Length/ cm | Diameter/ cm |
|---|---|---|---|---|---|
| 5 | Mirabilite mudstone | 0.332 | 9.76 | 5.183 | 2.468 |
| 6 | Dolomitic mudstone | 0.184 | 2.00 | 4.101 | 2.472 |
The experimental steps are as follows: first, the oil-bearing shale cores were washed with an organic solvent to remove the crude oil, then vacuumized and saturated with kerosene under pressure, then the NMR signals of them were tested; at this time, the salt in the cores has not damaged or dissolved; then, constant pressure deuterium water displacement experiment was carried out on the core samples in the HTHP NMR testing system to test the NMR signals of the cores under different displacement quantities (0.2, 0.5, 1.0, 2.0, 5.0, 10.0, 20.0 PV); finally, the cores after displacement of 20.0 PV (pore volume multiple) were dried at high temperature for 24 hours. The core samples were vacuumized and saturated with kerosene under pressure again to test the NMR signals of the cores saturated with oil for the second time.
2. Analysis of the results
2.1. Salt dissolution experiment
The principle of NMR test for evaluating salt dissolution is as follows: when salt is in solid state, there is no signal in NMR test; when salt dissolves in water, the space taken up by the soluble salt is filled with water, thus generating signals during NMR test. By comparing the signal quantity and distribution characteristics of NMR T2 spectrum at different time, the quantitative results of salt dissolution and the distribution position of solid soluble salt in the pore throat of the cores are obtained. Some of the test results are shown in Fig. 2.
Fig. 2.
Fig. 2.
T2 NMR spectra of 2 cores in salt dissolution experiment.
To evaluate the salt dissolution effect, the salt dissolution rate in the NMR test is defined, that is, the ratio of the increased signal quantity in the NMR T2 spectrum at a certain salt dissolution time point from the original state to the final T2 spectrum signal quantity after salt dissolution, as shown in equation (1). In this equation, the final signal of the salt solution T2 spectrum corresponds to the total pore volume occupied by the fluid in the core after salt dissolution. The increment of T2 spectral signal at a certain time point corresponds to the increment of pore volume at a certain time point caused by salt dissolution. The analysis results are shown in Fig. 3 and Table 4.
It can be seen from Fig. 2 to Fig. 3 and Table 4, as the injected water of 50 g/L in salinity continuously infiltrates into the cores, the salt in the cores is gradually dissolved and the NMR signal constantly increases. After the cores were soaked for 8 to 10 days, the salt dissolution stopped basically. According to the spectra, the final salt dissolution rates of core 1 and core 2 were calculated at 20.28% and 42.72%, respectively.
Fig. 3.
Fig. 3.
Curves of salt dissolution rates of the two cores in the salt dissolution process.
Table 4 Salt dissolution rates in each relaxation period of shale core salt dissolution experiment.
| Core No. | Lithology | Salt dissolution rate/% | Salt dissolution rates at different relaxation periods /% | |||
|---|---|---|---|---|---|---|
| <1 ms | 1-10 ms | 10-100 ms | >100 ms | |||
| 1 | Argillaceous dolomite | 20.28 | 0 | 5.45 | 11.53 | 3.30 |
| 2 | Argillaceous glauberite | 42.72 | 4.40 | 24.94 | 6.69 | 6.69 |
Since the transverse relaxation time is related to the pore throat size, the smaller the transverse relaxation time is, the smaller the corresponding pore throat is, and vice versa. The distribution of solid soluble salts in each pore range can be worked out. The soluble salts in the pores with the corresponding transverse relaxation time of less than 1 ms and more than 100 ms are small in quantity, but are mainly concentrated in the pores with corresponding transverse relaxation time of 1-10 ms and 10-100 ms.
2.2. Imbibition experiment
Fig. 4 shows the comparison of the recovery percentages of reserves and total salt dissolution rates of the 2 cores in the spontaneous imbibition experiment, of which the total recovery percent of reserves was calculated according to the change of the T2 spectrum.
Fig. 4.
Fig. 4.
Comparison of recovery percentages of reserves and total salt dissolution rates of 2 cores in spontaneous imbibition experiment.
The spontaneous imbibition of the inter-salt oil-bearing shale cores is mainly affected by three kinds of effects: (1) Water absorption: This process is mainly affected by capillary force, the lower the permeability, the greater the capillary force and the longer the imbibition distance. (2) Oil drainage: This process is mainly related to the pressure difference, permeability, starting pressure gradient and other factors. The greater the permeability, the lower the starting pressure, the smaller the drainage resistance, the easier the oil is discharged. (3) Salt solution: when the injected water has dissolved the soluble salt in the cores, the radius of the pore throats is enlarged, the seepage resistance is reduced, which makes the oil drainage easier, thereby improving the total recovery percent of reserves.
As shown in Fig. 4, the spontaneous imbibition experiment of the inter-salt oil-bearing shale cores can be divided into three stages: The first stage is from 1 to 10 h, which is the stage of strong imbibition and weak salt dissolution. It is mainly the process of water absorption and oil discharge. The second stage is from 10-200 h, which is the stage of strong salt dissolution promoted imbibition stage. In the stage, salt dissolution is strong and the salt dissolution rate increases rapidly, enlarging the pore throat radius of the cores, increasing the core permeability, decreasing the seepage resistance, increasing the oil drainage efficiency, making the oil drainage speed and the recovery percent of reserves through imbibition increased. The recovery percent of reserves through imbibition is almost linearly increased with the salt dissolution. This stage is mainly the oil drainage and salt dissolution process. The third stage is later than 200 h, which is the weak salt dissolution and weak imbibition stage. In this stage, the salt dissolution and imbibition are weak, which have little influence on the recovery percent of reserves.
According to the total recovery percent of reserves and the recovery percent of reserves through imbibition (the difference between the total recovery percent of reserves and the salt dissolution rate), the contribution rates of imbibition and salt dissolution were calculated to quantitatively characterize the relative strength of imbibition and salt dissolution in the spontaneous imbibition experiment of the oil-bearing shale cores. The results are shown in Table 5.
Table 5 Quantitative characterization of imbibition and salt dissolution in the spontaneous imbibition process.
| Core No. | Lithology | Imbibition contribution rate/% | Salt dissolution contribution rate/% | Recovery percent of reserves through imbibition/% | Total recovery percent of reserves/% |
|---|---|---|---|---|---|
| 3 | Argillaceous dolomite | 22.60 | 77.40 | 6.09 | 26.96 |
| 4 | Dolomitic mudstone | 36.30 | 63.70 | 17.94 | 49.43 |
It can be seen from Table 5, in the spontaneous imbibition experiment on the inter-salt oil-bearing shale cores, the recovery percentages of reserves of the two cores solely from imbibition are far lower than the total recovery percentages of reserves. Salt dissolution is very obvious, with a contribution rate of above 60%. Therefore, salt dissolution should be paid more attention to in the development of inter-salt shale oil.
The recovery percentage of reserves through imbibition and total recovery percentage of reserves of No.3 core are lower than those of No.4 core. The main reason is that No.3 core has no microfractures and is tighter in matrix, moreover, the core is slightly oil wet, making it difficult for water to enter and imbibition weaker; whereas, the No.4 core with microfractures and better physical properties is easy for water to get in, to it had stronger imbibition.
2.3. HTHP NMR online test
The stratified T2 spectra of the 2 cores in the displacement process are shown in Fig. 5. It can be seen from Fig. 5 that in the same core sample, the NMR signals at different cross sections or different parts are different, indicating that the distribution of microscopic pore structures inside the shale core is not uniform. By comparing the NMR images of the core saturated with oil for the first and second time, it is found that the latter image is brighter and stronger in signal, showing that after displaced with deuterium water, the salt in the core is dissolved, resulting in enlarged pores. The pore space after salt dissolution is filled with crude oil, thereby the NMR signal is much stronger than the NMR signal after it is saturated with oil in the first time. By calculating the increment of NMR signal, the porosity increased by salt solution can be obtained. According to calculation, cores No. 5 and 6 increased by 16% and 12% in pore volume and 1.62% and 0.19% in porosity respectively after salt dissolution, that is, the soluble salt volumes in the cores in the initial state accounted for 1.62% and 0.19% of the pore volumes of the two core samples respectively.
Fig. 5.
Fig. 5.
Stratified T2 spectra of 2 cores in the displacement process (the core displacement direction is from top to bottom).
By using the online test system, the conventional T2 spectrum was detected at different stages of core displacement, the permeability curve was obtained by direct test and the proportions of salt dissolution in different stages to the total salt dissolution were calculated using the T2 spectrum. From Figs. 6 and 7, it can be seen that in the constant pressure displacement process of the oil-bearing shale cores, with the dissolution of salt, the core increased in porosity, flow channel size, reduced in flow resistance, and enhanced in flow velocity, and the fluid permeability measured increased accordingly. After 5 PV of water was injected, more than 80% of the salt was dissolved; as the injection volume increased further, the pore volume increment became smaller and the permeability tended to balance.
Fig. 6.
Fig. 6.
Permeability variations of the 2 cores.
Fig. 7.
Fig. 7.
Variations of salt dissolution in the two cores.
3. Conclusions
In the salt dissolution experiment on the inter-salt shale oil reservoir cores taken from the Jianghan oilfield, the salt in the cores gradually dissolved with the continuous injection of water into the cores, and the final salt dissolution rates of the cores were 20.28% and 42.72%, respectively. The spontaneous imbibition of the inter-salt oil-bearing shale cores can be divided into three stages: strong imbibition and weak salt dissolution, strong salt dissolution and weak imbibition, weak salt dissolution and weak imbibition. In the spontaneous imbibition, salt dissolution is obvious, contributing more than 60% of the total recovery percentage of reserves. The HTHP NMR online tests show that the inter-salt shale cores are not uniform in microscopic pore structure. After salt dissolution, the cores had increase in pore volume, porosity and permeability.
Nomenclature
MA—increase of signal amount of T2 from NMR at certain salt dissolution time point from the original state of the spectrum;
MF—T2 spectrum final signal after salt dissolution;
S—salt dissolution rate, %;
T2—transverse relaxation time, ms.
Reference
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Formation, distribution, potential and prediction of global conventional and unconventional hydrocarbon resources
Characteristics and evaluation elements of shale oil reservoir
Status and prospects of shale oil & gas exploration in the United States
Status quo of tight oil exploitation in the United States and its implication
The exploration and development of shale gas in the U. S. is progressing fast, which also leads to thedevelopment of tight oil. Tight oil is the oil accumulating within the shale system, including black shale with very lowpermeability, argillaceous siltstone and interbeded sandstone. Tight oil can be free oil or absorbed oil. It is a continuousreservoir of self-generation and self-storage. The development of tight oil in the U. S. mainly performed in Bakken, EagleFord, and the Barnett shale zone. Bakken shale has oil resource of 230×108 t and recoverable resource of 5.9×108 t.Bakken shale located within the U. S. has oil of 3.7×108 t and similar amount of associated gas. Its cumulative oilproduction since 2 000 is about 2.8×107 t. Eagle Ford shale produces oil in the northern part, annual oil production ofabout 2×105 t. Barnett shale has average undiscovered oil resource of 1.4×107 t, ofwhich undiscovered tight oil resourceis 4.8×106 t. At present, Barnett shale has more than 8 000 producing wells, mainly produces oil in the northern part,gas in southern part. Up to the end of 2009, the cumulative oil production of “tight oil zone” has reached 7.7×106 t.China is a country rich in black shale. It is expected that the exploration of tight oil will get breakthrough soon.
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Several key issues and research trends in evaluation of shale oil
Shale oil retention and accumulation mechanism and resource potential of the Lucaogou Formation in Jimusar Sag, Junggar Basin
DOI:10.11764/j.issn.1672-1926.2016.10.1817
URL
[Cited within: 1]
In recent years,successful development of marine shale gas and rapid exploration of tight and shale oil in North America had driven petroleum exploration and development into the source rocks in the world.The Permian Lucaogou Formation in Jimusar Sag,Junggar Basin has been recognized as a series of semi-deep lake to deep lake source rocks,showing good prospect of shale oil exploration.Based on detailed-description of cores,slice observation,organic geochemical analyses,mercury injection and nuclear magnetic resonance of the Lucaogou Formation,it is concluded as follows:(1)Source rocks of the Lucaogou Formation show large thickness,high TOC and low maturity to maturity;(2)The shale reservoir space mainly included microstructural fractures of lamination bedding and matrix pores.The latter mainly consists of dissolved intra-particle pores,which were generally 100-1 000nm.The nano-size pore-throats are the main reservoir space with a ratio of 98% in the total space.Based on analyses of relationship among S1 content,TOC and RO of source rocks from the Lucaogou Formation and enrichment condition discussion of shale oil,it is considered that sources rocks with RO ranging from 0.7% to 1.0% and TOC≥2.0% are the favorable sections for shale oil and the residual hydrocarbon accumulation of shale oil has some characteristics,such as “adsorption of organic materials,store in nano-size pore throats and flow in the micro-fractures”.Key assessment parameters of shale oil and nuclear magnetic resonance analyses by the small patch method were used to preliminarily calculate the resources.Shale oil in Jimusar Sag have great potentiality with in-place resources of 2.55 billion tons,(theoretically)recoverable resources of 0.42 billion tons and technically recoverable resources of 0.04 billion tons, which are richly distributed around Well 30,Well 174,Well 251 and Well 32.These above understandings have important implication for shale oil exploration in Jimusar Sag.
Connotation and strategic status of in-situ transformation of shale oil
“Exploring petroleum inside source kitchen”: Connotation and prospects of source rock oil and gas
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DOI:10.11781/sysydz201602211
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Core samples of shales from the second (Eq2), third (Eq3) and fourth (Eq4) members of the Qianjiang Formation in the Qianjiang Sag were analyzed using X-ray diffraction (XRD) analyses to determin their mineral composition, brittleness and geochemical characteristics. The results showed that the shales from different formations have different mineral compositions and geochemical characteristics. The shales in Eq2 have sapropelic organic matter. The TOC content averages 1.38%. The Ro value ranges from 0.26%-0.5%, indicating an immature to low-maturity thermal evolution stage. Evaporite rocks are in high content. The shales in Eq3 have sapropelic and humic-sapropelic organic matter. The TOC content averages 2.53%. The Ro value ranges 0.5%-0.88%, indicating a low to medium-maturity thermal evolution stage. Quartz and clay minerals are in high content. The shales in Eq4 have sapropelic and humic-sapropelic organic matter. The TOC content averages 0.69%. The Ro value ranges 0.55%-1.3%, indicating a medium-maturity to mature thermal evolution stage. Carbonate minerals are in high content. The inter-salt shales in the Qianjiang Formation are characterized by "low clay content, low quartz content, high carbonate content, and low brittle mineral content" compared to those in the USA and other regions in China. The shales in Eq3 have higher brittle mineral content (average 56%) and higher brittleness index (average 75.3%), which show excellent exploration potential.
The pore structures of the shale about typical inter-salt rhythm in the Paleogene of Qianjiang Depression
Characteristics of micropore structure and seepage mechanism of inter-salt shale oil reservoir
