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In the Dan field, very high breakdown pressures were observed for wellbores drilled with a high azimuth with respect to the preferred fracture plane. The increased breakdown pressure was caused by significant near-wellbore friction. In scaled laboratory tests, variation in breakdown pressure was accompanied by a change in fracture geometry. Therefore, the variation in breakdown pressure in the field treatments could not be related simply to in-situ stresses.

In scaled laboratory experiments, we investigated the interaction of apropagating hydraulic fracture with natural discontinuities. We observed the hydraulic fracture geometry as a function of horizontal stress difference, stress regime, flow rate and discontinuity pattern. We observed the smallest amount of interaction for high flowrates. When the horizontal stress differencewas increased, the fracture was smoother. However, when we represented the tectonic stress ratio's, with a lower vertical stress compared with the maximum horizontal stress, we observed a higher fracture tortuosity. Introduction Mineback experiments1,2,3 in formations that were hydraulically fractured have provided the first views into complex hydraulic fracturegeometries in fractured reservoirs. They showed the formation of multiplefractures and large-scale interaction between a hydraulic fracture and natural fractures. These features will negatively influence the hydraulic fracture dimensions and affect the near-wellbore geometry. Encounters between apropagating hydraulic fracture and discontinuities may lead toarrest of fracture propagation,fluid flow into discontinuities,creation of multiple fractures andfracture offsets. The first three will result in areduced fracture length. Fracture offsets and multiples will result in areduced (local) fracture width. These width reductions may cause proppant bridging and consequent pre-matureblocking of proppant transport (so-called screen-out). Problems with early screen-out have been encountered in actual fracturing treatments in a fractured reservoir, the Minami-Nagaoka gas field in Japan4. In particular, abnormally high net pressures have been reported and are attributed to simultaneously propagating multiple fractures5,6,7. The combined analyses of fracturing and production performances also indicate complex fracture geometries. Most attention has been given to complex hydraulic fractures near the wellbore. Near-wellbore tortuosity is probably the dominant reason forpremature screen-out8. The influence of natural fractures (in thispaper termed discontinuities) on premature screen-outs has not received much attention. Observations, both from field8 and laboratory9data suggest that a high flow rate and very viscous fluid can induce a clean fracture in the preferred fracture plane. Presently, the recommended procedure for mitigating near-wellbore tortuosity is to initiate the fracture with viscous fluid (Cross-linked gel). The opposite conclusion could be drawn from numerical simulations of fluidflow into a fractured reservoir. In these simulations, the fluid flows in tojoints that are oriented in the direction of the preferred fracture plane for low flow rates. At high flow rates, the fluid flows in a radial pattern away from the wellbore10. The explanation is that the high flow rate induces a high net pressure and when the net pressure is much higher than the horizontal stress difference, the fluid can flow into fractures with any orientation. However, a limitation of these simulations was that the blocks in between the natural fractures could not break. Perhaps, in reality the formation of new fractures would yield a dominant hydraulic fracture at high flow rate. In this paper, we will describe the experimental set-up and the preparation of the fractured blocks. Then we discuss the test results for variation of the injection rate and stresses. Although a part of the experimental settings is prepared for the Minami-Nagaoka gas field, the conclusions drawn in this study are rather general.

Summary We have derived model laws that relate experimental parameters of a physical model of hydraulic fracture propagation to the prototype parameters. Correct representation of elastic deformation, fluid friction, crack propagation, and fluid leakoff forms the basis of the scaling laws. For tests at in-situ stress, high fluid viscosity and low fracture toughness are required. Tests on cement blocks agreed with the scale laws based on elastic behavior. Introduction In hydraulic fracture treatment design, numerical simulation is used to relate measured pressure to fracture geometry. As yet, there is no way to observe fracture geometry in field treatments, except in special tests with extensive monitoring (e.g., Ref. 1). Even then, much room is left for data interpretation. Laboratory tests should therefore serve as benchmarks for numerical simulations. Although there is an enormous difference in the scale of fractures in laboratory tests and in field applications, a numerical model should at least be capable of describing model tests with the appropriate boundary conditions. Many researchers have attempted to study fracture growth in physical model tests. Still, we must critically review previous experimental work in this paper because we think that such efforts can be greatly improved, at least in regard to two important (related) issues: correct scaling of the physical phenomena and stability of fracture propagation. Correct scaling implies that the physics of fluid-driven fracture propagation at field scale must be represented in the test. For instance, if tests are set up at in-situ stress and water is used for fracturing in the laboratory, the fracture pressures required to produce reasonable experimental times (and stable crack propagation) become so low that fracture toughness dominates the process, which is contrary to field observations (e.g., equal pressures during initial propagation and fracture reopening). In addition, the nonpenetrated zone at the fracture tip will disappear and the fracture will grow dynamically. Such experiments can bear no relation to the quasistatic process implied by field conditions nor to any credible numerical simulation of field fracturing.

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