The Kenshen tight gas field, located on the northern margin of the Tarim basin, western China, has extreme reservoir conditions of an ultra_depth reservoir (6500 to 8000 m) with low porosity (2 to7%), low matrix permeability (0.001 to 0.5 md), high temperature (170 to 190°C), and high pore pressure (110-120 MPa). Those conditions result in high completion costs and a significant difference in individual well production rates; with only one-third of wells drilled meets expectations. Previous studies focused on natural fracture(NF) and attempted to classify reservoir qualities based on the density of NF. Unfortunately, some NFs were closed or cemented by clay or calcite, and it is hard to distinguish open NF from closed NFs using well images in oil-based mud, which is widely used in this tight gas field for reservoir protection. Thereby, no positive correlation between NFs density and productions has been identified, even with the same stimulation treatment.
In this study, a comprehensive geological study was conducted to find a new way of characterizing the effectiveness of NF. First, the initial and development stages of NFs were recontructed through a tectonic activity study. Two stages were detected and showed different strikes. Second, petroleum system modeling technology was applied to simulate source rock maturation and gas migration, which revealed that gas generated in the Jurassic source rock migrated to the Cretaceous reservoir formation through faults activated in the same period as the late stage of NFs development. NFs developed earlier were closed or cemented by calcite of later deposition; those at late stage were open and effective for gas charge. Also in this study, Advanced analyses of borehole images indicated an alternative way to delineate NFs developed at different stages using geometry (i.e, crossed NFs shall include those ones developed at later stage). Parallel NFs with its development unidentified can be classified through the intersection angle of fracture strike and maximum stress direction. The smaller the intersection angle is, the easier it is for stimulation and alos the higher for the well production. Based on this study, we have divided reservoirs in the study area into three classes: class 1, reservoir with crossed NFs; class 2, reservoir with fractures of small intersection angle; class 3, reservoir with fractures of large intersection angle. This innovative reservoir classification through NF geometry is currently used in the field to determine formation stimulation method. Class 1 reservoir can benefit from acidizing alone with low completion cost. Class 2 reservoir of should be hydraulically fractured with acid. Class 3 reservoir of should be fractured with sand and proppant sand to achieve economical production.
Reservoir classification with NFs geometry had been applied successfully to guide stimulation design in the Keshen tight gas reservoirs. It is a practical and feasible way to choose the most appropriate stimulation treatment method to optimize well performance and avoid restimulation to reduce costs for this extreme type of tight gas field in western China.
Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Yang, Xin-Yu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University) | Zhao, Jin-Zhou (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University)
Hu Jia*, Xin-Yu Yang, and Jin-Zhou Zhao, State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation, Southwest Petroleum University Summary Foams can be used as well-killing fluid for workover operation in low-pressure oil and/or gas wells. However, foams usually come from gas injection under high pressure or high-speed stirring, which is complicated, expensive, and hazardous. In addition, the foam's stability is still limited by the current method of adding viscous polymer or the single crosslinking between the polymer and single crosslinking agent. This systematic study consists of optimization of different foaming agents, gel bases, and the effect of the GPC compositions (carbonate and acid) and their quantity, a macroscopic comparison of the stability and rheological properties of the double crosslinking and the common single crosslinking systems, with further investigation of their stability differences through microscopic research, and a coreflooding experiment to evaluate working performance. Within 4 days, the density of this novel foamed gel varies from 0.711 to 0.910 g/cm This is because of the function of the GPCs and foaming agent, which means that finer foams can be obtained to achieve target low density. Meanwhile, on the basis of the double crosslinking, a more compact gel structure is formed; thus the stability can be effectively improved. Results also demonstrated that this foamed gel shows a favorable performance of low fluid loss and temporary plugging, and the gas-permeability-recovery rate is up to 93.90%, which proves the gel to be effective for formation-damage control. This study suggests that the novel in-situ-generated foamed gel has the potential to achieve favorable well-workover performance in low-pressure and low-temperature reservoirs. Introduction In the later stages of mature oil-and gasfield development, workover is a frequent job for oil and gas wells. For safety consideration, pumping killing fluid into the wellbore is often a prerequisite to providing well control, even in ultralow-pressure reservoirs.
Jia, Hu (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University) | Chen, Hao (State Key Laboratory of Oil and Gas Reservoir Geology and Exploitation at Southwest Petroleum University)
Using mature Cr3+/partially hydrolyzed polyacrylamide (HPAM) gel can reduce filtration for water shutoff in the fractured reservoir. Whether the mature gel can act as a fluid-loss-control pill for well-workover operation is worth investigating. In this paper, we start a systematic experimental study to reveal the physical process and fluid-loss-control mechanism of the Cr3+/KYPAM (salt-tolerant polymer) gel used for overbalanced well workover. The polymer gel used in this study is formulated with a combination of 0.4 to 0.6 wt% KYPAM and added 0.02 to 0.04 wt% chromium acetate, which can provide a gelation time between 2 and 4 hours, and with a maximum gel strength of Code G at a temperature of 30°C. Results show that the mature Cr3+/KYPAM gel can withstand positive pressure of 10 MPa for a period of 120 minutes with average fluid-loss volume of 15 cm3 for the core permeability between 9.18 and 217 md, indicating a favorable fluid-loss-control performance. The regained-permeability recovery can reach up to 85% for different core permeabilities. Scanning-electron-microscope (SEM) pictures show that a dense structure was formed in the gel filter cake during fluid-loss experiment. The wettability results show that the core has a greater potential to increase its water-wet ability after interacting with Cr3+/KYPAM mature gel. Field test shows that a small amount of gel leakoff was observed during each reperforation process, whereas water cut decreased from 89.1 to 52.1% and oil production increased from 0.15 to 1.11 m3/d. This study suggests that the mature Cr3+/KYPAM gel can act as a fluid-loss-control pill in high-water-cut oil wells, which can provide an avenue to bridge the design philosophy of well workover and water shutoff.