Recent studies show that the flow along a horizontal well is not uniform or symmetrically distributed, as a larger volume of fluid enters the well near the heel. Flow equalization in horizontal wells is a state of the art strategy for assuring effective reservoir drainage and delaying the arrival of water breakthroughs. The idea is to provide a variable distribution of area open to flow along the horizontal section. The technique is applicable for several situations and is even more attractive in long horizontal section wells in heavy oil fields where friction losses in the well bore play an important role.
The concept of flow equalization has been successfully applied in onshore (slotted liners) and offshore (carbonate reservoirs) applications in Brazil. The next and most challenging step is to place gravel packs in wells where premium screens with non-uniform perforation distributions were made in the base pipe. The main issue is the excessive friction losses generated by the restricted cross flow near the heel of the well when the gravel is placed, which may generate pressures that overcome the usually low frac pressures in deepwater environments.
This article presents a case study for screen and gravel packing design for a typical deepwater application. Different screen base pipe perforation profiles are suggested and the gravel packing placement pressure was simulated. The strategy for optimizing flow equalization profiles with gravel packing pressures inside the operational window is defined by using an in house mechanistic model developed for OHGP operations.
The model was modified for this specific application, considering flow divergence during gravel placement and friction losses throughout the perforations. Results indicate that it is feasible to gravel packing screens in such scenarios and achieve attractive flow equalization results. It is important to highlight that this approach will make possible to promote an effective sand exclusion and to improve the reservoir drainage at the same time.
Non-uniform flow in long horizontal wells. Many authors 1,2,3,4 show that the produced flow does not occur uniformly along the horizontal section of the open hole, especially in heavy oil reservoirs. Due to the high pressure loss in the well, there is a preferential flow next to the heel and there is almost no flow observed in the toe. This difference in the production profile may lead to serious problems which significantly reduce the productive life of the well. These problems are the early breakthrough, usually associated with the premature arrival of the injected water or gas in IOR methods, and the formation of water cones when there is aquifer acting in the reservoir.
Basically, there are two different approaches that rule the well-reservoir flow. The first approach suggests the use of an infinite conductivity in the well, neglecting the well hydraulics effects. This leads to a super estimation of the production and an unreal flux distribution. This approach seems to be reasonable for low productivity systems where the well's friction losses could be neglected when compared to the friction losses that occur in the porous medium (Ozkan et al.1). However, for wells with long horizontal section, high production flow rate, low diameter, heavy oil or in multiphase flow, the wellbore hydraulics plays an important role in the production flow rate and should do not be neglected.
Vicente et al.5 present a more realistic modeling proposal for the system considering, in the well domain, a finite conductivity approach, including in the model the effects of friction, acceleration, gravity and reservoir influx. Unlike the results obtained by the consideration of an average infinite conductivity, this model tends to reflect non-uniform flow along the horizontal section (Fig.1).
Figure 1 shows two wells. The first one (blue line) could be modeled by the first approach due to the low reservoir permeability, which makes the flow through the porous medium govern the total friction losses. In this case, the flow occurs almost uniformly along the well. The second well (red line) could only be correctly modeled by the second approach. The reservoir presents high permeability and, consequently, the friction losses in the well should be considered.
Figure 2 shows the contribution in the production flow rate of each section of the well. The contribution of the initial section will depend on flow rate.