Operators, especially those managing production from deepwater reservoirs, are striving to produce hydrocarbons at higher and higher rates without exposing the wells to completion failure risk. To avoid screen failures, recent studies have favored high rate water pack (HRWP) completions over high-permeability fracturing (HPF), known in the vernacular as a frac&pack (FP) for very high rate wells. While a properly designed gravel pack (GP) completion may prevent sand production, it does not stop formation fines migration, and, over time, fines accumulation in the GP will lead to increasing completion skin. Although, and not always, the skin can be removed by acidizing, it is not practical to perform repeated acid treatments on deepwater wells, particularly those with subsea wellheads, and the alternative has been to subject the completion to increasingly high drawdown, accepting a high skin effect. A far better solution is to use a HPF completion. Of course the execution of a successful HPF is not a trivial exercise, and frequently, there is a steep learning curve for such a practice.
This paper explains the importance in HPF completions of the well trajectory through the interval to be hydraulically fractured, for production, not execution, reasons. A new model quantifies the effect of the well inclination on the connectivity between the fracture and the well via perforations both in terms of the total skin and the screen flow velocity. Guidelines are provided based on the maximum target production rate, including forecasts of multiphase flow, to size the HPF completion to avoid common completion failures that may result from high fluid rate and/or fines movement. Once the HPF is properly designed and executed, the operator should end up with a long term low skin good completion quality well that can be safely produced at the maximum flow rates, with no need for well surveillance and monitoring.
Introduction
The rationale for sand control completions is to prevent production of fines into the well. Given the high well costs in deepwater reservoir developments, profitability requires the wells to be produced at high rates, up to 40,000 STB/D for oil wells and 100
MMSCF/d for gas wells. Typically the reservoirs are capable of delivering the high rates, provided the well completions do not fail.
Operators dealing with subsea flowlines cannot tolerate even minimal fines production. Reasons include the possibility of fines build up, erosion of subsea chokes and hardware, and in severe instances even flowline plugging. Complex flow assurance measures only make the situation worse. Remediation of any of these problems would require an expensive workover. The current emphasis in the literature is on controlling the well flow rate to avoid exceeding estimated velocity or drawdown limits. This is a form of sand management when what is really needed is reliable sand exclusion at target production rates.
Veeken, et al.1 emphasized the importance of close alignment between the wellbore axis and the far field fracture plane. Unless the well is deliberately drilled to align with the fracture plane, their experiments showed that the well would have limited entry effects and reduced productivity due to poor communication between the wellbore and the hydraulic fracture. They stated that communication between the fracture and wellbore is determined by the orientation of the wellbore and perforations with respect to the in-situ stresses. There is also a possibility of forming of multiple fractures. Furthermore, they did a combined theoretical and experimental study to investigate key parameters for well-to-fracture connectivity. A key conclusion in the work by Veeken, et al.1 was a recommendation that the wellbore trajectory be drilled to align normal to minimum horizontal stress, either by drilling vertically through the productive interval or by turning the inclined well to this alignment.
Since then many operators and service providers have rejected the Veeken, et al.1 advice for various reasons. Cleary, et al.2 have recommended pumping strategies that tend to avoid multiple fractures. Also, many of the operators simply overlook altogether the importance of the well trajectory.
Furgier, et al.3 boast that they were able to place high permeability fracture planes in highly deviated wells, as though that were the sole objective, but they also report skins that are consistently well above zero. Furthermore, Furgier, et al.3 concluded that FP completions are common practice in 65° deviated wells and good completion efficiency is achieved (mechanical skin less than 5).