Highly Deviated to Horizontal Wells Fracture Deployment Considerations
Well Architecture - highly deviated to horizontal well profile
The objective for this type of wellbore architecture is to intercept more than one hydrocarbon unit, as these are separated with shale barriers, while maintaining more horizontality in zones with continuous high net sands. If the well azimuth is defined to obtain transverse fractures, the fractures will extend perpendicularly from the well into the reservoir increasing reservoir contact and improving hydrocarbon deliverability, when compared with a vertical well. However, there are key things to be considered in order for this to be correct.
The capacity to remove broken polymer from the proppant pack, affects the final effective proppant pack conductivity. The ability to remove fracture fluid from the proppant pack will be influenced by the reservoir fluids mobility and fracture to well connectivity, being this last one strongly influenced by near wellbore stress distribution.
It is required sufficient contact area between the fracture(s) and the well to compensate the limited contact area between those, leading essentially to the placement of more than one fracture per target unit. This is necessary, as the flow convergence will increase inertial pressure losses affecting inflow performance especially in gas wells.
(Diagram by Abass et. al.)
Breakdown and far field minimum stress contrast
The holistic integration of direct observations captured for selected highly deviated and horizontal wells, with a total of 150+ mini-fracture operations, 50+ main-fractures, HFM (hydraulic fracture micro-seismic), HPT (high precision temperature logs) and SNL (noise logs) data, including control flow back of selected zones and detailed finit elements modelling, confirmed that fractures will initiate along the well (longitudinal fractures), becoming transverse once the induced longitudinal fracture channel reaches undisturbed reservoir regions around the well. This detected near wellbore behavior will increase the challenges of fracture initiation, propagation, proppant transport, fracture fluid clean-up and final hydrocarbon inflow. Contrast between undisturbed in-situ stress conditions and breakdown pressures, will define the level of fracture propagation complexity near wellbore as it is described in the above figure. Understanding in-situ stress anisotropies, can provide an insight into the potential behaviour of fracture propagation near the wellbore, before defining wellbore positioning, trajectory, drilling and fracturing strategies.
(Diagram by Juan Chavez)
Perforation Strategy
Following the previously discussed point, it is clear that it is required to enhance a more direct path between the induced fracture channels, controlled by the far field stress, with the perforation openings. If there is a high contrast between the minimum stress (far field stress) and the break down pressure, at the selected fracture initiation zone, and a small perforation interval is used (e.g. less than 1 meter), it is possible to have the main transverse fracture channels not completely aligned with the perforation interval; this has been detected with SNL-HPT logs as flow behind casing.
HFM data have suggested in some cases, that the induced fractured channels are not nesessarily in direct aligment with the perforation clusters; this lack of alignment of the principal transverse fracture with the perforations intervals, shows the impair of flow capacity of the created transverse fracture.
(Diagram by Juan Chavez)
Horizontal Stress Anisotropy
The figure presents the predicted horizontal stress anisotropy distribution in a sector of field A in Oman. High and low horizontal stress anisotropy is displayed by hotter and cooler colors respectively. Zones with low stress anisotropy could lead to more fracture complexities when compared with higher stress anisotropy zones; understanding these variations is essential to define specific perforation and fracture strategies, to achieve effective fracture deployment and overall inflow performance.
(FracGeo horizontal stress anisotropy results)
Fracture vertical containment
Under normal stress or strike slip faulting, the induced hydraulic fractures vertical propagation will be affected by the contrast of petrophysical and geomechanical properties between the target unit and the upper and lower bounds formations, with depletion increasing the contrast of the prior mentioned rock properties.
The highly deviated trajectory targets the intersection of different sand layers across the different hydrocarbon units, placing transverse fractures to interconnect vertically these layers and maximizing the contact area between the fracture propped channel and the formations. However, fracture propagation has been observed limited or not possible in highly deviated trajectories intercepting units differentially depleted, where fracture initiation is performed in layers with less than 1 meter of net sand. Low injectivity associated with restricted fracture cross sectional area affects the maximum injection rate as the surface pressures reached the defined completion pressure limitations. As expected the low injectivity is the result of highly contained fracture channels.
The horizontal sections of the well trajectories were placed across uniform thicker sand bodies with less inter-bedded shale layers, this allows a better environment for fracture propagation and placement. However, it is not always possible to have this type of appropriate environments across the entire well trajectory, leading to a well path combining highly deviated and horizontal sections.
Effective propped flow region
The capacity to remove polymer from the proppant pack during early flow back and clean-up stages will determine the effective proppant pack flow region or effective fracture length. Polymer removal from the proppant pack is influenced, among other parameters, by the conductivity of the fracture channels, which are associated to the proppant pack effective permeability and fracture width. The fracture width is directly influenced by variation on elastic properties. For example, zones under the same loads during fracturing will create narrower fracture channels in areas with high Young’s modulus in contrast to wider fracture channels in areas with lower Young’s modulus; the same behavior is expected following stress variations between depleted and non-depleted regions.
Changes in fracture width will impact the fracture conductivity capacity and the subsequent effective polymer removal from the proppant pack. The figure above describes the results of a detailed numerical simulation, where the induced fracture propagates from the selected point of initiation in the target sand body, extending laterally and vertically, intersecting a shale barrier and reaching another target hydrocarbon unit. However, the fracture was able to propagate across these two units, the reduction in fracture width and overall fracture geometry at the transition (shale barrier) limits the polymer removal from the second target sand.
(GOHFER Modeling Results)
Minimum-Maximum horizontal stress orientation variability – Induced pressure nodes
It is important to highlight, that the observed minimum-maximum horizontal in-situ stress azimuthal variations that can take place are significant and could lead to reorientation of the fracture planes, as the fracture propagates from one specific minimum-maximum stress orientation to another. Contrary to common perception, hydraulic induced fractures will potentially create more complex paths, as propagation evolves across different minimum-maximum stress orientations. The figure describes how the induced fractured channels will be potentially connected, leading to the creation of pressure nodes along the areas of stress reorientation.
(Diagrams by Juan Chavez)
Pressure nodes
Pressure nodes are defined as areas where the flow path is greatly restricted as a result of significant reorientations of the induced fracture during its propagation. High flow convergence will be generated as the flow reaches these pressure nodes, increasing inertial effects that will impact inflow performance. As previously described, pressure nodes can be created due to minimum-maximum horizontal in-situ stress azimuthal variations. However, variations on the induced fractured path near wellbore will potentially generate pressure nodes, which are influenced by the contrast between the breakdown pressure and the far field minimum stress, as described in the figure and discussed previously.
(Diagrams by Juan Chavez)
Flow convergence and impact over flow performance
Forchheimer’s equation describes the flow through porous media. For gas wells the second term of the relationship describes the inertial effects, where the quadratic of the velocity dominates the total pressure losses as the gas contracts and expands from the matrix into the fracture and to the well. When placing transverse fractures, gas convergence effects are unavoidable as the flow reaches the interception between the fracture and the well. However, additional flow convergence will be at the induced pressure nodes, influenced among other parameters by differential depletion.
(Diagrams by Juan Chavez)
More information in SPE SPE-200073-MS (Chavez et.al) or contact us for continuing the conversation
Future areas of conversation
1- Beyond Conventional Mini-Frac Analysis - Practical Field Applications.
2- Understanding production forecasting uncertainties in fractured wells.
3- Modeling inflow performance in complex fractured geometries for highly deviated to horizontal wells.
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