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Liquid carbon dioxide (CO2) fracturing technology is one of the waterless fracturing technologies. It has the advantages of avoiding the use of water, reducing damage, and increasing production by improving the reservoir pressure. However, the low viscosity of liquid CO2 and the difficulty to pump proppant are the main technical challenges. No conventional thickening agent can provide the required thickening used in 100% liquid CO2. In this paper, the problem of thickening gelled liquid CO2 has been solved by developing a new surfactant and thickening agent. Surface active agent can make the liquid CO2 gel by forming wormlike micelle or cylinder micelles structure. The cylinder micelles enhance the viscosity through entanglement inter-actions above a critical concentration. Rheology and friction properties of liquid CO2 gel are evaluated through high pressure pipeline rheological experimental device. The viscosity of liquid CO2 gel fluid changes under different pressures (10 to 20MPa), temperatures (0 to 100 °C)and different shear rates. The experiment result shows that the effective viscosity of liquid CO2 gel fluid is between 7.654 ~ 20.012mPa.s. The liquid CO2 was thickening with viscosity increase at 86 to 498 times under the same conditions. The field application of the new liquid CO2 based gel fracturing fluid in two wells of Jilin oil field in China shows that the production has been increased over 100%. 19.8 m3 of proppant has been successfully pumped to the reservoir in one well, and the mean proppant concentration is 6.8%. Liquid CO2 based gel fracturing fluid provides a new fracturing system with less formation damage to fracturing operation. This paper will be beneficial to all engineers and technologists who are currently working at waterless fracturing applications.

A large number of natural gas resources of medium-high rank coal reservoirs has been achieved in Qinshui basin and other areas in China, which presents broad prospect of exploitation. Nevertheless, this low-porosity (3%-5%), low-permeability (0.01mD-3mD) type of reservoirs require hydraulic fracturing to realize commercial development. As relatively long period of drainage and regional depressurization are needed before the initiation of coalbed methane (CBM) production, the fractures firstly offer channels for drainage. Meanwhile, it is easy for the soft coal and proppants to be embeded. Therefore, long fractures and high conductivity through fracturing treatments are needed to gain better production performance. Thus, the key factors to get optimal effectiveness of well completion are to accurately acquire understanding of the hydraulic fractures expanding and supporting conditions. This paper introduces a joint fracture-diagnostic technology of microseismic mapping and microdeformation measurements to monitor nine wells of two cluster well platforms of CBM reservoir. The pattern, orientation and size of fractures are obtained from microdeformation measurements, and the scope of stimulation is obtained from microseismic mapping. Some conclusions from the studies are as follows: (1) it is hard for the fractures in coal seam to propagate, and their lengths usually range from 44 m to 119 m. The fracture length estimated from microdeformation measurements is smaller than the results from microseismic mapping. (2) A new method to estimate stimulated reservoir volume based on microdeformation measurements through calculating volume envelope is set up. The SRV estimated from microdeformation measurements is much less than the one from microseismic mapping. As the CBM reservoir has a high leak-off coefficient, the SRV estimated from microdeformation measurements is closer to the reservoir volume controlled by the effective propping fractures. (3) On the same platform, the orientation of fractures in the latter constructed well changes due to the stress interference from the former constructed well, and the orientation variation of fractures in the last constructed well is the biggest. These understandings are of important influences on CBM fracturing design and construction, which can be used to determine reasonable stimulation volume, reasonable construction sequence and interval of platform wells based on the real fracture propagation characteristics, and finally to obtain the optimal well performance.

Multi-stage fractured horizontal wells can create fracture networks and increase the contact area between fracture and matrix to enhance well productivity and EOR. It has become a tendency to pump large volumes of fluids and proppants with higher and higher slurry rate during hydraulic stimulation. While field production has presented that not all productivities have positively relation with the increase of stimulation scales. Some small-scale fractured wells even perform better than the massive treatment ones.To investigate this phenomenon, a new evaluation experiment studied by CT scanning and rock mechanics testified the existence of the fracture surface damage, and some key factors were revealed. Moreover, we established a new mathematical model of fracture surface skin with segment characteristics using fluid coupling method based on the classical model of PKN and KGD. Comparison of the Cinco-Ley model and new model revealed that influence of the fracture surface damage skin on productivity was only 5% using Cinco-Ley model, while the influence was 50% using our new model.The results indicated that for a specific low permeability reservoir, if high net pressure can't create complex fracture, it would bring formation damage in the near well. We put forward a method for low damage treatment as following: 1)utilize the newly developed fracturing fluids such as slick water, low concentration densifier, linear gel (not cross linked), low molecular weight fluid, etc.; 2)Optimize minimum viscosity of fracturing fluid, then optimizing the corresponding pumping rate; 3)Optimize combination of fluid and proppant type and size according new mathematical model; 4) Try acid-fracturing during pad stages so as to minimize formation damage and fracture damage to obtain an optimized propped profile.The technology has been put in to filed application in 45 wells, the performance of post-fracturing is very remarkable with the daily oil rate being 14m3/d increased more than 32.2% that of the past well stimulation, and it has a great significance in the near future.

We will review recent work on the proposed hierarchical ring-based architecture (HiRing) proposed for data center networks. We will discuss the architecture and initialdemonstrations of optical switching performance and time-domain synchronization

Spontaneous imbibition is an important process to increase oil recovery in fractured carbonate reservoirs. Due to the nano-scale pores and throats distributed in tight oil reservoirs, capillary pressure became much larger, which may result in a much stronger imbibition. An experimental and modeling was adopted to simulate drainage and imbibition process in hydraulic fractured tight oil reservoir. Firstly, 400 mm×100 mm×30 mm core samples were used to simulate forced displacement and spontaneous imbibition of fracture surface at in-situ conditions of pressure. Secondly, 1D model for counter-current imbibition was solved on some assumption of relative permeability and capillary pressure, numerical results obtained by COMSOL as verification. Results have indicated that recovered oil was 0.19 mL in spontaneous imbibition condition while was 0.62mL in combined condition of forced displacement and spontaneous imbibition. Saturation front contacts the sealed end-face much faster with forced pressure condition. According to this phenomenon, it can be inferred that the main direction of aqueous phase in the shut-in period is form large pores to smaller pores. Aqueous phase was pushed into the large pores by forced pressure, and imbibed into smaller pores in the function of capillary pressure. 1D model of 2 phases counter-current imbibition solved with Galerkin method is in correspondence with numerical result at the same assumption. With the increase of dimensionless distance (X) and dimensionless time (T), water saturation profiles were drew and were contrasted with CT scanning. Forced displacement and spontaneous imbibition simultaneously occurs during fracturing and shut-in duration. Study of this can provide a reference for soaking management and a good way to increase well productivity.

We have measured the interfacial tension between Daqing crude oil and a ternary system containing a weak base, S6 surfactant, and a polymer. We have studied the effect of the concentrations of the weak base Na2CO3, S6, and the polymer on the interfacial tension. The results show that a weakly alkaline three-component system reduces interfacial tension better than a nonalkaline two-component system. As the polymer concentration increases, the time required to achieve ultra-low interfacial tension increases. Sodium carbonate not only reduces interfacial tension but also acts as a sacrificial agent to reduce surfactant consumption.

Massive discharge of CO2 has serious impact on the global climate and threatening the survival of humanity and life. How to make waste profitable becomes the subject of attention. Against this issue with my research domain, CO2 could be injected in the oilfield as a kind of oil-displacing agent, especially the ultra-low permeability oilfield with difficulty in water injection. This technology not only displaced oil but also sealed up part of CO2 underground forever. This passage summarized CO2 displacing mechanism, and did research on the opportunity of advanced CO2 injection and the style of cycle CO2 injection by reservoir numerical simulation application in a typical block using Eclipse software. Through comparing with six proposals, the consequences indicated that CO2 flooding technology could be applied in ultra-low permeability oilfield. Advanced CO2 injection and the style of cycle CO2 injection could both have good flooding effect and pressure maintenance degree. The best opportunity of Advanced CO2 injection is 4 months. In cycle injection proposals, increase-decrease style is better than increase-suspend style. These conclusions could not only provide new theoretical basis for gas flooding in ultra-low permeability reservoirs, but also solve the reduction of CO2.