Fracture systems

On the other hand, the addition of fibers may cause undesired properties of the cement [1759]. Fibers can actually increase pore and fracture systems in latex cements. The amount of fibers in a fiber seal cement influences the porosity and permeability while affecting compressive strength. During acid treatment of the formation, the fibers in the cement can be easily dislodged and extracted from the cracks, leaving pore spaces behind. 

Because of NGC s co-occurrence with coal, the targeted coal seam locations and their geographical distribution are typically well known from coal assessments. Natural gas from coal is produced by reducing the natural pressure within the coal seam by creating fracture systems (so-called fracs ) to allow the gas to release from the coal and then flow through a well to the surface. 

The production of tight gas is technically very demanding. The major differences from conventional production arise because of the poor permeability of tight reservoirs, where the natural gas cannot flow as quickly to the well or in sufficient volumes to be economic, and where production rates are usually quite low. The principal prerequisite for economically producing tight gas is, therefore, to improve reservoir permeability, e.g., by artificial stimulation techniques, such as hydraulic fracturing (i.e., the generation of artificial fracture systems). 

The clay-based grouting technique uses clay slurries as a base for grout solutions. These solutions are injected into bedrock fracture systems to inhibit or eliminate groundwater flow through these pathways. The clay slurries may also be used as a base for slurry wall construction. 

The oil industry has developed and used a double porosity model to describe flow in certain fracture systems (7). Little data on application to actual field problems are available in the literature suggesting that this model has had only limited success and has been used only after the fact, not in a predictive mode. 

The concept involves the injection and detonation of a liquid chemical explosive in natural or previously induced fracture systems or the use of a pelletized explosive to enlarge and extend these fractures to provide fragmentation and interwell communication. This study is one of few known research efforts to evaluate results of detonating sheetlike layers of explosive to increase flow capacity in confined rock formations. The literature contained little information to guide the design of the experiments. Some related work, however, had been conducted by a few individuals and oil field service companies. Briefly, the earlier work resulted... 

A combination of displacing NG1 into a natural fracture system and using pelletized TNT in wellbore shots fragmented oil shale between wells at relatively shallow depths ranging from 60 to 100 ft. Extensive fragmentation extending to a radius of approximately 48 ft and extensive fractures to a radius of 90 ft were disclosed by various evaluation methods. 

The location and physical complexity of hard-rock fracture systems make it difficult to determine the mechanisms affecting radionuclide migration under field conditions. Techniques are needed that, under closely controlled conditions, provide data relevant to mass transport in the field. Development of two such techniques is described here. 

With the possible exception of selenium, a two-site, double first-order (DFO) model shows an improvement over single site-models for describing sorption of the radionuclides studied. The dependence of sorption on alteration history in the majority of cases indicates that experiments with systems representative of well-weathered fracture systems are necessary to obtain data applicable to actual disposal vault conditions. 

The fracture system is modeled as a Id aquifer with high permeability (20 mobile cells with the numbers 1-20), each one connected to immobile cells (number 22-41, number 21 is reserved for the column s discharge). The content of the immobile cells can only be transferred to the mobile cells by diffusion. The value for a is calculated from Eq. 101 assuming De = 210"10 m2/s (range from 3-10"10 to 2-10"9 for ions in water, approximately one order of magnitude less for water in clays), 9im = 0.15, a = 0.1 m (thickness of the stagnant zone accompanying the fracture), and f,, i = 0.533 (Table 17)... 

Secondary hydrocarbon migration is the movement of hydrocarbons after expulsion from a source rock through carrier and reservoir rocks or fault and fracture systems. 

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