1. Introduction
With the world’s increasing need for energy and the gradual decline of conventional oil and gas production, attention has been turned toward unconventional reservoirs such as shale oil and shale gas [
1]. Resources in tight reservoirs are substantial worldwide. Global gas reserves in shale reservoirs are estimated to be 716 trillion m
3 [
2]. America has turned unconventional resource production into a commercial process. Tight sand production and shale gas account for about 30% of total gas production in America [
3]. China has the largest natural gas resources in tight reservoirs or tight sand reservoirs [
4,
5]. However, although there is large resource potential in tight reservoirs, it is much more difficult to extract oil and gas from a tight formation than from conventional reservoirs, mainly due to the small pore size and the ultra-low permeability of the matrix [
6,
7].
Hydraulic fracturing combined with horizontal drilling has been widely used to enhance the production of oil and gas from tight sands or shale reservoirs [
8,
9]. Hydraulic fracturing improves hydrocarbon transport by increasing the formation’s permeability and enhancing extraction. The main approach is to cut the low-permeability matrix into small pieces to increase the rock surfaces and connectivity. The fine induced fractures maximize the area of contact with the rocks, allowing hydrocarbon extraction from thousands of meters of rocks, rather than tens or hundreds of meters available with merely vertical wells [
10,
11]. Fracture networks connect each small piece of the matrix to the hydrocarbon flow path to the production well [
12,
13]. Many successful cases worldwide demonstrate that hydraulic fracturing enhances oil recovery in unconventional reservoirs [
14,
15]. Hydraulic fractures connecting with natural fracture systems ensure a more effective stimulation in fractured reservoirs, but the occurrence of arrest, diversion, and offset may inhibit the fracture growth and proppant placement. Blanton’s [
16] conducted laboratory hydraulic fracturing experiments using pre-fractured material to investigate the interactions between hydraulic fractures and natural fractures, aiming to provide information that helps to examine the conditions under which such inhabitations happen so that detrimental effects can be prevented. His results show that the morphology of hydraulic fracture is significantly affected by the pre-existing fractures, and hydraulic fractures are more likely to cross natural fractures only in high stresses and under high pre-existing fracture angles. Maity and Ciezobka [
17] developed a novel image-processing workflow method to detect and analyze the proppant distribution in more than 200 through-fracture Permian Basin core samples to investigate proppant transport behavior in stimulated formation volumes during hydraulic fracturing treatment. The observations show that the presence of hydraulic fracture and of natural fracture and their interactions do not necessarily result in high proppant concentration in the cores, and stress contrast and lithology changes can govern the local in-depth proppant distribution. Their study provides a new method to systematically analyze core samples for the distributions of proppant and similar particles. Cipolla et al. [
18] identified the benefits of tortuosity, multiple fractures, and the apparent activation of natural fractures and verified their potential using both fracture modeling and G-function analyses. Luo et al. [
19] conducted a reservoir simulation using a geo-model to simulate the unique flow regime in multi-stage fractured horizontal wells compound formation linear flow. Results showed good agreement with field data of the Bakken formation.
In recent years, due to the rapid development of the tight oil/gas industry, the oil/gas recovery technique has made great progress. The appearance of volume fracturing has resulted in a great increase in tight oil and gas production [
20]. The conventional hydraulic fracturing treatment aims to create a bi-wing open fracture in tight reservoir formations [
21]. The fluid flowability is mainly affected by one fracture, but the fracture cannot improve the flowability of the total reservoir formation because, in the vertical direction of the fracture, the oil/gas still experiences a long-distance matrix flow in the low permeability porous media, as shown in
Figure 1a. The single fracture limits the final oil/gas recovery efficiency, as the fluid flowability in the vertical direction is not increased [
22,
23]. To improve reservoir productivity, the fracture should be designed with a high fracture length and a high fracture conductivity [
24]. The volume fracturing technique can generate single open fractures and can create and extend complex fracture networks [
23,
25]. In volume fracturing treatment, the reservoir formation was reconstructed and broken up through the fracturing method, forming several main fractures. By using the high flux, a large volume, and low viscosity fluids, together with the “staged and multi-cluster” perforation, secondary fractures can be generated in the main fractures. In the same way, second-order secondary fractures, and third-order secondary fractures, can also be created to form a complex fracture network in the formation [
25,
26], as shown in
Figure 1b. The volume of the formation with fracture networks is called the stimulated reservoir volume (SRV) [
27,
28].
Fractures generated by volume fracturing are not only conventional open fractures, they also experience a shear/sliding dilation process [
29], which leads to larger contact areas between the fracture faces and formation matrix. Due to the great number of created fractures, the complex fracture network and the large fracture-contact area, the oil/gas in the stimulated reservoir formations can flow along the shortest distance in any direction from the matrix to the fractures, significantly increasing the overall formation permeability [
25,
26,
30]. Therefore, the reservoir formation can be effectively reconstructed, and reservoir productivity can be greatly improved.
Both conventional fracturing and volume fracturing are sand fracturing techniques. According to some criteria, sand fracturing treatment with a fracturing fluid volume smaller than 1500 m
3 is called conventional fracturing, and that with a fracturing fluid volume larger than 1500 m
3 is called volume fracturing [
31]. However, volume fracturing still has other characteristics in terms of operations. In volume fracturing, the fluid injection rate is relatively high, usually larger than 10 m
3/min, but it can be slightly smaller in some specific reservoirs. Volume fracturing is usually operated with a smaller proppant (70/100 mesh~40/70 mesh) and a lower sand ratio, with an average range of 3–5%. In some cases, the sand ratio can be around 10%, depending on the formation properties. Slickwater is mostly used as the fracturing fluid [
32,
33]. In some conventional fracturing theories, the injection of a significant volume of fracturing fluids with high pressures would cause a serious filter loss problem of the fluid in the matrix and forming shorter hydraulic fractures, resulting in formation damage and non-effective fracturing treatment. However, volume fracturing treatment always accompanies by injection of large volume fracturing fluids. First, this is because the segmented multi-cluster fracturing technique is usually employed in the volume fracturing treatment to form fracture networks [
34,
35,
36]. In conventional staged fracturing treatment in horizontal wells, the single cluster perforation method is usually used, which can only support the low volume and low rate of fracturing fluid injection, not the large fluid injection required by the multi-cluster fracturing. Second, the volume fracturing is more suitable for and usually being applied in brittle formations, which are more easily to form a great number of complex fractures during the large volume injection fracturing treatments. Third, because of the low permeability of tight oil rocks, the filtration loss of fracturing fluids to the matrix is very small, most of the large volume fluids would flow into the numerous induced fractures or the natural microfractures, which could increase the stimulated reservoir volume. Study results from Li et al. [
37] show that volume fracturing can significantly increase the production of tight oil reservoirs. A larger fractured volume and increased fracture networks could result in greater oil production. Chen et al. [
31] compared the investment and benefit between conventional hydraulic fracturing and volume fracturing in the Southern Sichuan Basin and found that tested gas production yield from volume fracturing is about 2.12 times that of conventional fracturing technology. The wide application of volume fracturing in the field could reduce the circle returns and decrease total costs.
The Changqing oilfield is a regional oilfield affiliated with PetroChina Company Limited (PetroChina). In 2012, the oil-gas equivalent exceeded 45 million tons, making it the biggest field in China. The work area is located in the Ordos Basin, with an exploration area of 3.7 × 105 km2. Chang 7 is a block rich in tight oil with estimated resources reaching up to two billion tons. Hydraulic fracturing has been tried for tight oil recovery in Chang 7. However, pilot tests and field data show that conventional hydraulic fracturing treatments cannot efficiently improve the oil production rate, whereas volume fracturing treatment in the Chang 7 tight oil formations can lead to a significant increase in the tight oil production and a great decrease in the water cut.
In this study, the geological and physical properties of Chang 7 tight oil reservoir were characterized first. The tight oil recovery ability of the volume fracturing treatment was investigated through core flow experiments and field scale practice. The results of this work may provide some instructions with the applicability of the volume fracturing technique in tight oil reservoirs for EOR.
5. Conclusions
In this work, the performance of the volume fracturing treatment to enhance tight oil recovery in the Chang 7 tight oil reservoir, the Changqing oilfield, was studied through experimental investigation and field-scale practice. Conclusions drawn from this study are as follows:
(1) The Chang 7 tight oil reservoir in the Changqing oilfield possesses a wide distribution of hydrocarbon source rocks that are rich in organic matter. The tight oil generation intensity of the Chang 7 reservoir is estimated to be 495 × 104 km2, and the total amount of generated hydrocarbons can be as high as 2473.08 × 108 ton. The favorable hydrocarbon source rocks in the Chang 7 reservoir ensures a high capacity of tight oil generation and accumulation.
(2) Core analysis from the pilot areas of the Chang 7 tight oil reservoir indicates poor physical properties of the reservoir formations. The average porosity of the formations is around 8–9%, and average permeability is about 0.11–0.14 mD. Due to the low porosity, low permeability, and poor pore connectivity, it is difficult to recover the tight oil from formations without fracturing treatment.
(3) Fractures developed in tight cores can significantly improve fluid flow conductivity. The increased flowability is crucial to oil recovery improvement in tight oil reservoirs. However, fractures with permeabilities too high above those of the matrix may lead to a severe water channeling problem in the formation. The injected displacing water mainly flows through the fractures with overly high permeability, leaving the tight oil in the matrix almost un-swept. Therefore, when applying fracturing treatment to improve the oil recovery in tight oil reservoirs, developing fractures with appropriate permeabilities, which increases the flowability and decreases the water channeling possibility, is important for field operators.
(4) The imbibition effect plays an important role in tight oil recovery enhancement in low-permeability porous media. Core experiments show that developed fractures can remarkably increase the imbibition rate in tight cores, as the contact area between the fracture and the matrix is significantly increased by the formed fractures. In some fractured Chang 7 tight cores, the movable oil recovery improved by the water imbibition effect can be as high as 51.32%. The imbibition effect in tight cores increases with the decrease in core permeability.
(5) A field-scale application of the volume fracturing treatment exhibits a prominent increase in tight oil production in the Chang 7 reservoir. Compared with the conventional fracturing treatment, volume fracturing can produce a larger number of fractures with more favorable properties to improve the flow conductivity. Moreover, volume fracturing treatment in horizontal wells resulted in a much larger stimulated reservoir volume around the treated wells, which can be 4.9 times greater than that of conventional volume fracturing.