simulate a fracture. When ICDs were included in the model, the fracture experienced a water- injection rate increase of only about 10%; there was a 10-fold jump when only a standard screen was used in the same model. A third evaluation used a full-field reservoir
model to estimate the effect of the improved water distribution. This evaluation included an injection well equipped with ICDs in scenarios similar to those analyzed by the near-wellbore simulator in the first two cases. The simulations concluded that given a high- permeability channel, the use of ICDs increased cumulative oil production by 10% over that achieved with use of a standard screen alone. They also showed that with no high-permeability zone present the ICDs would improve cumulative oil production by 1% and that the most likely case was somewhere between the two (right). In 2008, based on the success of this water-
injection project, Statoil installed another injection well equipped with ResInject ICDs in the Svale structure. The well has performed according to objectives.
Control of the Future The success of ICDs is now drawing the attention of producers concerned with inefficient flow from long laterals. Among these are heavy oil pro- ducers. For more than 15 years, steam-assisted gravity drainage (SAGD) has been the process of choice for development of fields producing heavy oil. Despite this history, the process is not well understood.15
It may be that the current
steam distribution in horizontal injection wells designed to heat and drive oil to deeper produc- tion wells is less than optimal, particularly in heterogeneous reservoirs. Besides the common difficulties associated
with creating uniform flow through any reservoir, two-phase water systems (liquid and vapor) used in SAGD wells add to the difficulty of control. In addition to single-phase-flow concerns relating to fluid-velocity profiles and pressure drops associ- ated with piping configurations, many other fac- tors including flow-regime effects, water holdup, phase splitting, droplet size, slugging and other variables are introduced in two-phase flow.16 Typically, SAGD injection liners are slotted
along the entire section—a configuration that does little to optimize steam distribution. To fight the heel-toe effect, many operators today use dual steam conduits in horizontal steam injec- tors—one landed near the heel of the well and a second near the toe.
In an effort to better understand SAGD pro-
duction and find more efficient solutions to its challenges, Chevron has constructed a surface horizontal steam-injection facility at its Kern River field near Bakersfield, California, USA. Researchers there are focusing on evaluation and deployment of equipment for accurate and reli- able steam placement along laterals in horizontal injection wells to improve recovery.17 Their proliferation in recent years is testi-
mony to the effectiveness of ICDs. Use of ICDs has allowed operators to realize full value from the ability to drill long laterals, thereby exposing large volumes of the reservoir to the wellbore. In fact it can be argued that inefficient drainage owing to uneven flow through the reservoir threatened to impose economic limits on well- bore length that were far short of the technical limits. Today’s lengths are measured in kilome- ters rather than in meters, as they were less than a decade ago.
Production history
80 70 60 50 40 30 20 10 0
0
Modeled standard completion, high-permeability channels
Modeled standard completion, no high-permeability channels
200,000
Cumulative oil production, m3 400,000
600,000
800,000
1,000,000
>Water-cut models. For the most part, the actual water cut in this well was lower than predicted by either model. Though the field is in early production, the improved numbers may reflect enhanced sweep achieved by the use of ICDs. (Adapted from Raffn et al, reference 13.)
OSWIN09/10—Rick, story #2—Figure 13 —RvF
Winter 2009/2010
37
Water cut, %
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