A conventional proppant pack may lose up to 99% of its conductivity due to gel damage, fines migration, multiphase flow, and non-Darcy flow. Therefore, pillar fracturing was developed to generate highly conductive paths for hydrocarbon to flow. This paper describes experimental results and numerical models of a new method of generating stable proppant pillars The proposed treatment method depends on fingering phenomena observed when a less viscous fluid, that does not carry proppant, is injected to displace a more viscous one that carries proppant. The low-viscosity fluid will channel through the high-viscosity fluid and create isolated proppant pillars. This method promises to reduce proppant costs, pumping horsepower, and gel damage compared to conventional treatments. Large-scale experiments (Slot tests: 2-ft height and 16-ft length) were performed to evaluate the development and stability of the created channels. In additional, a computational fluid dynamics (CFD) model was constructed using commercial CFD software, to simulate the experiment and to scale it up into full fracture dimensions. The study focused on effects of surface injection rate (1 to 120 bpm) and viscosity ratio (from 2 to 200) between the two injected fluids. Experimental results and numerical modeling confirmed that viscous fingering phenomena can be used to create a pillar fracture with conductive and stable channels. The numerical CFD model was able to accurately predict the experimental results. Increasing the injection rate reduces the main channel width while increasing the channel branching. Full piston displacement behavior was achieved after 60% of the fracture height, when a high-viscosity fluid displaced a low-viscosity fluid and their viscosity ratio was greater than 5. By reducing the viscosity ratio between the two fluids, the created channel shape converts from cylindrical (where the beginning and end of the channel have the same width) into conical behavior (where the beginning of the channel is wider than the end). This explains why the length of the channel decreases with the viscosity ratio between the two fluids. The distance between proppant pillars tends to be reduced with increasing distance from the wellbore, or with reduced pulse stage volume, time, or rate. A full description of the created channel (distance between proppant pillars) characteristics (size, width and length) will be presented in this paper.

Fracturing fluid trapping is one of the major sources of damage after well stimulation as the remaining fluids in the pore space reduce the effective hydrocarbon permeability. Especially in tight formations, fluid trapping can require significant time to clean up, even at a high production rate. Outcrop cores have traditionally been used to confirm the existence of damage and to quantify it. However, it is difficult to clearly discern the trapping mechanism in cores and to accurately determine the trapping location and the volume of residual fluid.In this study, a reservoir-on-a-chip approach was adapted to visualize the residual water blocking process of fracturing fluids. The major advances in using this approach are the clear visualization of the trapping process in the pore space and the control of testing parameters including formation wettability, reservoir/stimulation fluid properties, flow rate, and reservoir pore-space geometry. This study includes two sections: A fluid mechanical study to determine which reservoir conditions require chemical treatments to mitigate water blocks; and a chemical evaluation study to determine how well chemicals, such as surfactants, can alleviate severe water block conditions. Experimental results confirm that the geometry of the pore throat plays a critical role in trapping and releasing fluid. Furthermore, displacing reservoir fluid at high rates, or with a higher oil viscosity, increases cleanup efficiency. With this fundamental understanding, the reservoir conditions that require chemical treatment can be identified. Cleanup efficiency was significantly improved by using a surfactant. The designs of engineered chemical treatments to mitigate water blocks under specific conditions will be discussed in this paper. These new findings expand the industry's understanding of the fluid mechanics behind residual fluid trapping, capillary effects, and the implications for engineered fracturing fluid systems.

In deviated wellbores, the relationship between friction pressure and hydrostatic pressure differs from that in vertical wellbores. The change in this relationship increases the need for accurate slurry friction pressure modeling. Because of deviation, incremental slurry friction pressure changes are more significant than incremental changes in hydrostatic pressures. Real-time calculation of an accurate bottomhole treating pressure in deviated wellbores is more difficult to achieve, than in vertical wells, because of the lack of accurate slurry friction models. 'Abnormal' surface treating pressures, which are caused by this change in relationship, were recorded while fracturing deviated wells in the Prudhoe Bay Field in Alaska. The significance of this relationship is presented along with observed slurry friction pressure data obtained through the use of bottomhole pressure recorders. A methodology and mathematical model for more accurate calculation of slurry friction pressure is presented for these conditions. Introduction While performing fracturing treatments in vertical wells with the tubular and treatment conditions presented here, the surface treating pressure will normally decrease when proppant is added and proppant concentrations increase. 'Abnormal' or increasing surface treating pressures have been recorded while fracturing highly deviated wells. Misinterpretation of these surface pressure increases can cause erroneous decisions to be made during the fracturing treatment. Figure 1 is a hypothetical plot of surface treating pressure, slurry rate, and proppant concentration versus time for a frac job performed in a near vertical well. This example shows a continual decrease in surface treating pressure with proppant addition. Figure 2 is a hypothetical plot of the same parameters on a well that has a high angle of deviation from vertical. Note that at first, the surface treating pressure decreases when proppant is added but then begins to increase as the proppant concentration increases. The hydrostatic and tubular friction pressures must be accurately calculated during the treatment in order to obtain the net bottomhole treating pressure for proper analysis. Hydrostatic pressures are fairly simple to derive if the slurry density is monitored at the surface. The tubular friction pressure must be calculated based on a friction pressure model that is incorporated into the real-time computer monitoring package. This parameter is much more difficult to predict because of the variables involved. Because of the higher significance of friction pressure in highly deviated wells, proper slurry friction pressure modeling is even more critical. To properly understand this pressure phenomena and its significance, one must first have a thorough understanding of surface treating pressure and its components. FRACTURING PRESSURES The fracturing surface treating pressure is a function of four basic pressure components: hydrostatic head, pipe friction pressure, perforation friction pressure, and the formation fracturing pressure or bottomhole treating pressure. Their relationship is expressed in the following equation: (1) P. 771^

Over the recent past, hydraulic fracturing processes have been the subject of increasing scrutiny of the chemistries and processes employed, with particular concern directed towards protection of water resources. For example, operators and fracturing services companies in the United States have been targeted by both federal and state legislators and the Environmental Protection Agency (EPA) with audits, inquiries, Congressional hearings, and subsequently, new regulations requiring full public disclosure of the chemicals pumped in fracturing treatments and controlling the use of certain chemistries, such as diesel oil. Much effort has been expended to identify alternative, more environmentally acceptable products which maintain the needed material performance characteristics and cost basis.A new quantitative process to evaluate and rank the hazards posed by various treating additives and potential alternatives was presented in SPE135517. The process is based upon the Globally Harmonized System for Classification and Labeling of Chemicals (GHS) which has been adopted by the United Nations to standardize information about communication of the hazards and toxicities of chemicals. After the respective material hazards have been quantified, they may be ranked for comparison with like-purposed additives for their anticipated safety, health, and environmental impact. Then, the best candidates by that measure can be assessed for performance and cost. In sum, the process is a valuable tool to guide fracturing R&D and their chemical suppliers toward development of more environmentally acceptable products and systems.

The oil and gas industry has been relying on hydraulic fracturing techniques to proliferate production from low permeability reservoirs. Despite significant advancements in tools and chemicals used in the fracturing processes, maximized production and recovery of hydrocarbons is still unattainable due to challenges with proppant placement and settling. Even when heavy gelation fluids are used, proppants suspensions are subject to particles settling in the presence of vibration, and/or due to fracturing fluids breaking before the fracture close. Furthermore, the fractures are typically vertical; in this case the proppant has a tendency to settle in the lower portion of the fractures while the upper portions close in the absence of proppant. This can lead to impairment in the geometry of the fracture and well productivity. This paper describe a new ultra-lightweight proppant having a low specific gravity (1.06) that can withstand stresses up to 8,000 psi at a temperature of 275°F. Such proppant is easier to transport and due to its buoyancy will stay suspended in low viscosity fluids leading to fractures that are much better propped. This new material has been fully characterized for its properties including mechanical and thermal properties. It applicability to far field applications has been validated through conductivity testing in a partial monolayer mode as a function of loading and temperature. The Modeling was used to establish its application in mixtures with conventional proppant for vertical coverage of the fracture. Experimental evaluation of the proppant show that its conductivity decreases as the stress and temperature increase due to the nature of the material. The results show that this proppant can be used up to 8,000 psi at 275°F in a partial monolayer mode. Placing the proppant in a partial monolayer application is required due to the flexibility of the proppant material and to maximize conductivity through the proppant.