No abstract

The production wells in tight glutenite reservoirs have great potential for refracturing, because most of fracturing fluid and proppant flow into the first-class layer with lower initiation pressure during initial stimulation with multi-layer simultaneous fracturing treatment. However, layer segmentation during refracturing can be a challenge, especially in vertical wells. Using only mechanical segmentation tools is of high risk and sometimes ineffective. This paper presents a new refracturing technology for vertical wells employing diverting agents. The segmentation tools are rarely needed in the new refracturing technology. The implementation procedures are as follows: First, reservoir characteristics, remaining oil distribution and water content are evaluated to identify the target layers of refracturing. Second, through the classification of predicted initiation pressure, number of temporary plugging and diverting fracturing are determined. The dosage of chemical diverting agents is designed. Finally, refracturing treatment are performed with an injection procedure of "fracturing fluid and proppants (dredging existing fractures) + granular plugging agents (blocking existing fracture entrances) + fracturing fluid and proppants (creating new fractures) + powdery plugging agents (blocking new fracture tips) + fracturing fluid and proppants (creating complex fracture networks)". The refracturing treatment was performed in Well B1401 located at Junggar Basin in China using the method presented in this paper. The fracturing construction curve of Well B1401 shows that obvious pressure increase was observed when the diverting agents was added, and the initiation pressure or propagation pressure of subsequent fracture was monitored higher than that of previous fracture. It is suggested that proper agents or combinations can effectively plug the opened fractures and generate high enough pressure in the fractures to initiate branch fractures. The production log data indicate that five new layers begin to produce oil after refracturing operation, and the daily oil production of Well B1401 remarkably increased from 1.5 t/d to 9.8 t/d in the field test, which verifies the validity of the tool-free refracturing of vertical wells employing diverting agents. This study provides a new refracturing technology for vertical wells in tight glutenite oil reservoir employing diverting agents is presented. The segmentation tools are rarely needed in the new refracturing technology. It has been applied to hundreds of low-yielding oil wells in tight glutenite reservoirs of Junggar Basin, China. The average annual oil production per well has increased by 950t. It also provides guidelines to the engineers with respect to refracturing design and commercial viability. In addition, this technology is not only suitable for vertical wells, but also for horizontal wells.

Shale gas reservoirs are characterized in low gas abundance, poor permeability, lower natural productivity than the lower limit of industrial oil flow, and rapid formation energy decline. At present, the technology of horizontal well drilling and staged hydraulic fracturing is widely used for the exploitation of such low-porosity and low-permeability reservoirs. The long well section of the horizontal well in the reservoir and the hydraulic fractures formed by fracturing act as the "underground expressway" for the deep gas in the reservoir to flow toward the wellbore. Their combination can greatly increase the production performance of the oil and gas resources in the reservoir. Staged multi-cluster fracturing in horizontal wells is the key technology to achieve the profitable shale gas production. The results of on-site downhole perforation imaging and distributed optical fiber temperature and acoustic monitoring show that there are obvious non-uniform liquid inflow and expansion phenomena in each cluster of fractures during the fracturing process. Relevant research results also show that factors such as the heterogeneity of the reservoir and the stress interference caused by the propagation of multiple fractures are the main causes of the non-uniform propagation of hydraulic fractures. Therefore, it is accessible to simulate the complex balanced expansion of each cluster of fractures in the fracturing section to improve the coverage of hydraulic fractures in the horizontal well section with numerical simulation methods based on the basic theory of elasticity and fracture mechanics, to reveal how the above engineering geological factors influence and control the fracture propagation. The results of the simulation of the fracturing treatment section of the deep shale gas horizontal well by the fracture propagation model are consistent with the micro-seismic monitoring results,which has obvious significance for accelerating the exploitation of difficult-to-exploit resources and guaranteeing the supply of gas resources.

The accurate prediction of pore pressure relates directly to various important affects oil and gas field exploration and development including drilling engineering design and formulation of oil and gas reservoir development plans. The well logging information with unique advantages such as high vertical resolution and capability of continuous measurement has been widely used in formation pore pressure prediction. Currently, though the industry has developed many methods for formation pore pressure well logging prediction, they may not be all used to calculate formation pore pressure in actual production. And it may be difficult to guarantee the prediction accuracy with a single method. In order to accurately predict formation pore pressure, this paper systematically reviewed domestic and foreign literatures on formation pore pressure well logging prediction, explained the methods and principles of each prediction technique in detail, and summarized the applicability of each formation pore pressure prediction technique in detail. This paper concluded that both the effective stress method and the Bowers method could be used to accurately predict the formation pore pressure, and the empirical statistical model method also had high prediction accuracy, while the equivalent depth method and the Eaton method which are subject to the accuracy of the normal compaction trend equation had relatively poor prediction effect. It will be a trend in this field to construct the formation pore pressure nonlinear prediction model based on mechanical parameter tests in the study area with organically integrating geophysical well logging and pressure detection data. The study area is located southwestern China, the deep formations that more than 4000 meters are high temperature (150-180 deg C). Thermal-related secondary pore pressure generating mechanism may become active leading to higher overpressure and difficulties in prediction. For the case study, an empirical relationship of overpressure impact factors versus temperature of shale was proposed. An accurate pore pressure model generated using available well-scale geomechanical model and overpressure impact factors. With an integrating fully coupled PPP model as foundation, the integrated approach helps deep wells to reduce serious wellbore instability caused by abnormal formation pressure, wellbore collapse and other complex drilling problems.