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ABSTRACT: Hydraulic fractures are known to interact with natural fractures and other heterogeneities in rocks. When injection rates, fracture apertures and propagation pressures are low, natural discontinuities in the rock tend to arrest fractures, and fracture planes are deviated from the direction dictated by in-situ stress, forming local stepovers and pinchpoints. One conceptual possibility to radically increase propagation pressure and injection rate is to release energy and create a pressure pulse, generating motive force pushing fluid into the fracture, locally inside the wellbore. Compared to conventional injection using surface pumps, this allows the reduction of fluid friction losses inside the well, the release of energy at higher rates, and the containment of high pressure away from surface equipment and personnel. In this paper, we derive and discuss analytic estimates for the final extension of axisymmetric hydraulic fractures created by a local pressure pulse in the wellbore. Analytic equations explicitly specify the relationship between mechanical properties of the rock formation, in-situ stress conditions, parameters of the wellbore energy source generating the pressure pulse and resulting size of the fracture. Analytic estimates are helpful for fast engineering estimates and preliminary feasibility assessments of fracturing systems based on wellbore pressure pulse. In the end, we illustrate analytic predictions with numerical modeling.
Interaction of hydraulic fractures with naturally occurring rock fabric such as weak bedding planes, depositional bounding units and mineralized and organic-filled fractures can result in complex fracture geometry with branching, stepovers and arresting on these fabric elements. In the regions of the hydraulic fracture that are far from the wellbore, fracture complexity can be desirable because it may create additional fracture surface in the given rock volume and therefore improve overall hydraulic contact between the well and the reservoir. In the regions of hydraulic fracture that are close to the wellbore, fracture complexity can be detrimental because it leads to reduced fracture conductivity, increased pressure drops and potential issues with successful proppant placement. During production, reduced fracture conductivity in the near-wellbore zone can choke flow from the distant part of the fracture and decrease the value of the entire fracture system.
Zhang, X. (CSIRO Earth Science and Resource Engineering) | Jeffrey, R.G. (CSIRO Earth Science and Resource Engineering) | Bunger, A.P. (CSIRO Earth Science and Resource Engineering) | Thiercelin, M. (Schlumberger RTC-Unconventional Gas)
Using large-scale hydraulic-fracturing experiments on tight shale outcrops, three dominant regions controlling stage production were identified--the connector between the wellbore and the fracture system, the near-wellbore fracture, and the far-wellbore fracture network. The particular nature of these regions may change depending on the play, the reservoir makeup, its relation to the in-situ stress, and the distribution of rock properties; however, these regions are always well differentiated. Understanding the role of each of these components in hydrocarbon production is fundamental to identifying the dominant sources of fracture-conductivity loss and accelerated production decline. Achieving economic production from nanodarcy-scale-permeability, organic-rich-mudstone reservoirs requires creating large surface area by hydraulic fracturing. More importantly, economic production depends on preserving the created surface area and fracture conductivity during long-term production.
If there is a closed-in passive fracture within the compressed region, this causes an increase in its fluid pressure. The magnitude of pressure increase is a function of the distance between the two fractures (passive and active), the net extension pressure in the active fracture, and the overlap area. This pressure increase is defined as fracture shadowing and has been used for estimation of different fracture parameters, including orientation and length. This paper presents the mathematical background of fracture shadowing, including relationship between net extension pressure, distance between fractures, extent of each fracture, and volume of existing passive fracture system. Through actual field data, it shows that shadowing can be used as a very simple and cost effective tool for estimation of different fracture parameters. Shadowing in the same well is used to determine fracture growth pattern as well as a rough indicator of orientation. In offset wells, shadowing can provide estimation of fracture orientation, type, length, and in some cases conductivity. Paper demonstrates and recommends use of fracture shadowing as a simple and inexpensive additional diagnostic tool for determination of fracturing parameters.
Suarez-Rivera, Roberto (Schlumberger) | Behrmann, Larry (Schlumberger Consultant) | Green, Sid (Schlumberger and the University of Utah) | Burghardt, Jeff (Schlumberger) | Stanchits, Sergey (Schlumberger) | Edelman, Eric (Schlumberger) | Surdi, Aniket (Schlumberger)
Abstract Using large-scale hydraulic fracturing experiments on tight shale outcrops we identified three dominant regions controlling stage production: (1) the connector between the wellbore and the fracture system, (2) the near-wellbore fracture and (3) the far-wellbore fracture network. The particular nature of these regions may change depending on the play, the reservoir fabric, its relation to the in-situ stress, and the distribution of rock properties. However, these regions are always well differentiated. Understanding the role of each of these components, to hydrocarbon production, is fundamental to identify the dominant sources of loss of fracture conductivity and accelerated production decline. The conditions promoting the loss of fracture conductivity, fracture face permeability and surface area in contact with the reservoir vary significantly along the length of the hydraulic fracture. By separating the induced fractured area into three characteristic regions of reservoir contact, we isolate the dominant drivers of loss of production per region, and obtain the best compromise for sustained stage productivity. We used large-scale hydraulic fracturing experiments to develop and validate the concept. These were integrated with scaled-down measurements of fracture conductivity, proppant embedment and the effect of rock-fluid sensitivity. We find that the critical conditions for productivity for the wellbore-connector depends on mechanical stability considerations and are independent of reservoir quality. The critical conditions for productivity from the near-wellbore fracture are solids retention in the proppant pack, and reduction of fracture face permeability due to proppant embedment. The critical conditions for productivity from the far-wellbore fracture are loss of surface area and retention of fracture conductivity. Results provide a framework for improving fracture design for improved long-term productivity. This is achieved by understanding the conflicting requirements between three regions of flow within the fracture and selecting the optimal compromise between these.