New Flux Surveillance Approach for High Rate Wells

Abstract

Wells in high permeability reservoirs requiring sand control are commonly completed either with a high permeability fracture (HPF) or a high rate water pack (HRWP). These prolific reservoirs are capable of delivering high production rates, but the downhole flow velocity becomes a limiting factor. The downhole velocity is one of the most important factors in completion failure. To determine a safe producing rate for prolific wells, the current best practice is to monitor flux to avoid completion failure due to screen erosion or destabilization of the annular pack. Flux is the flow velocity at a critical location in the completion: at the screen face to avoid screen erosion, or in the annular pack to avoid pack destabilization. The commonly applied method for mathematically estimating the flux from the mechanical skin relies on a number of parameters that cannot be uniquely quantified, including the proppant permeability, the proppant turbulence factor, and the fracture skin. The calculated flux is highly sensitive to these uncertain parameters. When the flux is overestimated, the well rate will be unnecessarily restricted. Underestimation of the flux risks completion failure. Most practitioners assume values for uncertain parameters, calculate the flux, and back-calculate the number of flowing perforations. Sensitivity studies will show the potential pitfalls of this technique. Instead, this paper presents an alternative approach to determine the flux as the total flow rate divided by the flow area, which, in turn, can be related to the number of perforations effectively conducting fluid from the reservoir to the wellbore. For the HPF case, this means how many perforations connect the fracture to the wellbore, which is a function of the angle between the well trajectory and the far field plane of the hydraulic fracture. When the angle cannot be determined due to a lack of the necessary stress measurements or stress isotropy, the flux will be calculated based on the pressure drop across the perforation tunnels obtained from the mechanical skin. The method and its advantages over existing techniques will be demonstrated using field data from deepwater Gulf of Mexico (GOM) wells. Introduction When wells are drilled at an inclination, the intersection between a vertical fracture and the wellbore may be extremely limited and may complicate treatment execution and further restrict well productivity (Martins et al. 1992). In one reservoir, efforts to improve wellbore to fracture connectivity in deviated wells including 180 degree phased, oriented perforations, and aggressive tip screen out designs with high conductivity proppant were shown to compensate for these problems (Vincent and Pearson, 1995). However, superior treatment execution and well production are often achieved when fracturing vertical wells rather than inclined wells.

Comprehensive Model for Flow Behavior of High-Performance Fracture Completions

“…The oil well case has been discussed in previous papers and Tosic, et al (2008)). The gas well case is new and illustrates especially the ability of the DVS model to address turbulence in the fracture, in radial flow to the GP, and through perforation tunnels.…”

“…In the fracture we simplify the intersecting region between the fracture and the wellbore by a rectangle with width 2r w and height h c , which can be calculated approximately by h 1 + h 2 as in Fig. A-3 from Tosic et al (2008). In order to get this contact region in the fracture, we need to add two horizontal dividing lines.…”

“…First we need to calculate the number of perforations, N c , connecting the fracture and the wellbore as in Tosic et al (2008). Neglecting non-Darcy flow, the pressure drop is computed as in Welling (1998): …”

“…While this model enables determination of the number of flowing perforations strictly by geometry with no assumed values, the Wong et al (2003) estimate for the number of perforations is highly dependent on the assumed values for proppant permeability, beta factor and mechanical skin. Tosic, et al (2008) showed wide variations in the values for proppant permeability and beta factor that may apply, and pointed out that the mechanical skin is difficult to quantify because the total skin determined from pressure transient analysis (PTA) includes the sum of the mechanical skin and a negative fracture equivalent skin. The latter is seldom possible to quantify because the fracture flow regimes are short lived in HPF wells and masked by wellbore storage.…”

“…However, Norman (2003) reported that HPF completions have shown much better long term performance than GP completions. Since many deviated, high rate wells have HPF completions, the Tosic et al (2008) model suggests there should be more HPF well completion failures than have been observed. A plausible explanation for this apparent inconsistency was presented by Zhang et al (2009) who introduced a new model allowing for flow both through the fracture and bypassing the fracture through perforations in the GP region that are not connected to the fracture as shown in Figure 1…”