The advantages of this steady-state modeling
are quick designs, high-resolution near-wellbore models and quantification of the upside potential of oil production with decreased water and gas cut. However, this approach delivers only a snap- shot in time and cannot predict or quantify the value of delaying water or gas breakthrough. This step requires the investment of considerably more time and effort to perform dynamic simula- tions, such as using the Petrel software reservoir engi neering workflow in conjunction with the Multi-Segmented Well (MSW) model of the ECLIPSE reservoir simulator. This model treats the well as a series of seg-
ments and allows engineers to model indepen- dently three-phase flow, liquid-gas holdup and the implications of using ICDs and flow control valves over the life of the well. Each modeled seg- ment can be angled upward or downward and can contain different fluids to account for an undulat- ing well path. Ideally, dynamic modeling is accomplished
using a full-field geologic model. But often this is not practical, even with high-performance, paral- lel computing hardware, because of the long com- putational simulation necessary to complete the runs. A more practical solution begins by extract- ing a sector model from the ECLIPSE full-field simulation model that can extract flux, pressure or no-flux boundary conditions to reduce dynamic simulation time while honoring the geologic het- erogeneity and interference from nearby wells. Reducing the number of geology grid cells
offers more-sensitive runs. Furthermore, the sec- tor model can be combined with the full-field model. The area of interest is then modified to refine the grid and upscale from the geologic model, and the well trajectory is loaded. The segmented well with ICDs and packers is then created in the ECLIPSE simulation.
The Sweet Spot The advantage gained by the ability to quickly incorporate new data into completions was dem- onstrated in a field offshore Malaysia. Having opted, for economic reasons, to drill two long horizontal wellbores into a target characterized by a thin oil rim with a gas cap and active aquifer, the operator included ResFlow ICDs in the com- pletion design. Because they are nozzle-type devices, it is easy to adjust and optimize them on location in response to new LWD data without costing valuable rig time.
Oil Rate, bbl/d
Open hole 7,759
3 x 4 mm, second joint 8,821
3 x 4 mm, joint 9,290
698 798 837 2,411 1,263 762 23.7 12.5 7.6 3,794 3,752 3,740
> Packer density impact. By isolating compartments within heterogeneous formations, it is possible to reduce water cut and sand production considerably while maintaining or, as in this case, increasing oil production. Reservoir engineers first test the model for optimum packer density before determining the number and sizes of ICDs needed for the completion. In this example, installing three 4-mm-diameter nozzles per joint reduced water cut to 7.6% compared with 23.7% in an openhole completion. At the same time production increased from 7,760 to 9,290 bbl/d [1,233 to 1,476 m3/d] without a significant increase in bottomhole pressure (BHP). When the same nozzle configuration was used on every second joint, water cut was reduced to 12.5%.
Gas Rate, Mcf/d
Water Rate, bbl/d
Water Cut, %
BHP, psi
The wells were part of a second-stage devel-
opment of a mature field; challenges included a stacked sand reservoir with uncertain dips and unconsolidated sands. The company also sought to avoid formation damage during drilling, mini- mize drilling costs, and maximize production and drainage of remaining reserves while minimizing water cut.7 While the horizontal well option was less
costly than an alternative plan that included drilling three deviated wells, it was technically more challenging. It required one 2,000-ft
[610-m] lateral and one 1,000-ft [305-m] lateral to be placed precisely with respect to fluid con- tacts and reservoir boundaries (below). This option also required openhole sand screens and passive ICDs to enable production contribution from the entire length of the wellbore. Rotary steerable systems were used to drill
the wells as far from the water contact as possi- ble to delay water production and as close to the overlying shale boundary as possible to capture attic oil. An LWD assembly that included a deep azimuthal resistivity distance-to-boundary tool—
Gas zone
Oil zone
Water zone
OSWIN09/10—Rick, story #2—Figure 06
A B
0 0
m ft
750 2,500
>Well placement. As part of an ongoing field expansion, this small area within a field offshore Malaysia was targeted for development using one 2,000-ft lateral (A) and one 1,000-ft lateral (B). The thin oil rim (green) is bounded by a strong waterdrive (blue) and a gas cap (red).Depth contours are labeled in feet. (Adapted from Maggs et al, reference 7.)
Winter 2009/2010
33
–4,000
–3,875
–3,750
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