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Physical Control Measures
Published in Larry W. Canter, Robert C. Knox, Ground Water Pollution Control, 2020
Larry W. Canter, Robert C. Knox
Two of the more popular methods of grout installation are the stage and packer methods. In stage grouting, holes are drilled to the geologic seam closest to the land surface and the grouting fluid is injected. The holes are then cleaned, drilling continues down to the next seam and grouting continues. The process is repeated until a sufficient depth has been obtained. In general, the stage method proceeds downward, utilizing increasing injection pressures. In the packer method, holes are drilled to the maximum planned depth. A zone of specified thickness is then partitioned off by placing packers at the top and bottom of the zone. Grout is then injected into the zone between the two packers. The mechanism is then moved up to the next zone to be grouted and the process is repeated. The packer method moves upward from the bottom utilizing decreasing injection pressures. Advantages of the packer method include: grouting pressures can be adjusted specifically to a particular foundation depth; walls of the borehole remain smooth and an excellent seal with packers can be achieved; and high pressures used in the stage method which may cause fracturation are avoided. However, these advantages can be offset by increased equipment needs and time for installation (Bowen, 1981).
Underground Injection
Published in Stephen M. Testa, Geological Aspects of Hazardous Waste Management, 2020
Injection wells must be designed in a manner to protect all formations containing useable waters penetrated by the well. Several methods for well completion have been devised based upon formation and waste type, among other factors (Figure 11-10). An injection well typically consists of concentric pipes. The outermost piping, referred to as surface casing, usually extends below the deepest usable water aquifer, and is cemented from its terminus to the ground surface. Two strings of piping extend to the injection zone: the outer long string and inner production (injection) tubing. The long string is cemented back to the surface casing. The production tubing is used to conduct the fluids to be injected under pressure or gravity flow. Injected fluids may also be injected through perforations at the bottom of the long string. A packer is usually set at the bottom of the well between the production tubing and long string casing (annular space) to prevent waste from backing up into the annulus. The annulus is then filled with an inert fluid, and maintained under pressure slightly higher than the waste injection pressure to prevent leaks into the annular space. The wellhead is capped and equipped with an automatic shut-off valve, and gauges to monitor injection pressure, injection rate, and annulus pressures. A typical hazardous waste injection well is shown in Figure 11-11.
The Performance of Slug Tests
Published in James Johnson Butler, The Design, Performance, and Analysis of Slug Tests, 2nd Ed, 2019
The major disadvantages of packer-based methods are that packers can be expensive, the central pipe upon which the packer is mounted may restrict flow, and the packer must be cleaned prior to use at another well. Although inflatable packers (Figure 3.6A) can be expensive, mechanical packers (Figure 3.6B) are an inexpensive alternative for situations where the packer is positioned in the cased portion of shallow wells. If inflatable packers are necessary, such as in a straddle-packer system for multilevel slug tests (e.g., Butler 2005), sliding-head packers are best because the same packer can be used in wells of a range of diameters. A significant advantage of a mechanical packer is that the central pipe is usually larger than that in an inflatable packer for the same size well. This, however, is only important for tests in high-K media where the central pipe of the packer may restrict flow, that is, energy losses within the central pipe may be on the order of or even exceed those in the formation.
A new process to develop marine natural gas hydrate with thermal stimulation and high-efficiency sand control
Published in Petroleum Science and Technology, 2023
Tianyu Luo, Songxia Liu, William K. Ott
Multi-stage sliding sleeve packers and chemical diverting agent are used together to create multi-layered fractures for multi-layered reservoirs. The sliding sleeve packer coarsely divides formation layers, and a plugging agent is injected into each layer to finely subdivide the layer. This repeats 2–3 times. Multi-stage sliding sleeve packer (Figure 2) can create 3–5 layers each time. The chemical diverting agent (Figure 3) is water-soluble collagen, fiber, or resin particles. It can temporarily plug cracks and perforations, increase pressure to open new cracks, then partially or mostly dissolve a few hours after fracturing, and will not damage the formation (Fang, Feng, and Zhang 2018). After each fracturing stage, chemical diverting particles are injected before the next stage. It can achieve 2–4 sub-layers in one segment.
Analysis and control of annular pressure caused by leakage effect of completion string for HP/HT/HHS gas wells in Sichuan Basin
Published in Petroleum Science and Technology, 2023
The production curve of the well from the beginning of production to date is presented in Figure 11. From the figure shown, the annular pressure increases from 8.57 MPa to 37.7 MPa in the first stage of production. Meanwhile, during the rise of annular pressure, there are several obvious processes of sudden drop, rise, sudden drop and rise. The liquid level monitor shows that the annulus liquid level decreases from the wellhead to the downhole 3900 m, indicating that a large loss of annulus protective fluid occurs in this stage. As the annular pressure continues to rise, H2S is also detected in the annulus gas sample, and the composition of the annulus gas sample is basically the same as that of the produced gas, as shown in Table 2. Based on the characteristic of annular pressure rise, analysis result of annulus gas sample, and annulus protective fluid loss, it is determined that the tubing-casing annulus has escaped and there are leakage points on both the packer and the completion string. In order to determine the risk of annular pressure, the pressure relief and recovery test is performed in well site and the annular pressure recovery curve is obtained, which is illustrated in Figure 12. Compared with the judgment chart, it can be judged that well A in this stage goes beyond HPHR pattern. Combined with annulus protective fluid loss and H2S contained in annulus gas sample, it can be determined that the wellbore safety risk of well A in this stage is very high.
Numerical investigation of a double-circulation system for cuttings transport in CBM well drilling using a CFD-DEM coupled model
Published in Engineering Applications of Computational Fluid Mechanics, 2020
Bing Shao, Yifei Yan, Xiaomei Wang, Fujin Liao, Xiangzhen Yan
The novel DCS is developed mainly to provide assistance with removing the cuttings accumulations resulting from a fast drilling rate that tend to build up in the horizontal and curved sections of the wellbore, which can cause complications like sticking that can result in drilling accidents. The working mechanism of a DCS is illustrated by Figure 1. After the second well completion, the interior casing and accompanying tools such as the centralizer, packer, and injection joint are lowered to the connector, which is used to connect the interior casing to the exterior casing. During the drilling process, the flow of main circulation (FMC) is injected from the wellhead and travels down the interior of the drill rod, coming out from the drill bit into the inner annulus space. Simultaneously, the flow of assisted circulation (FAC) is injected from the wellhead into the outer annulus and flows through the nozzles, meeting the FMC in the inner annulus where the joint flow returns to the wellhead carrying the cuttings.