12 10 8 6 4 2 0
Heel Measured depth Toe
> Reducing the influence of high-flow-rate areas. In a heterogeneous model ICDs reduced the fluid inflow rate (blue) at the heel (within orange circle) to half that predicted for a screen-only completion (red). However, they increased the inflow rate from the lower two-thirds of the well (within green oval) including the toe.
pressure drop between formation and wellbore (above).5
They accomplish this by changing the
flow regime from the Darcy radial flow within the reservoir to a pressure-drop flow within the ICD. Each of the basic types of ICD uses a different operating principle to achieve this backpressure. The pressure drop within a nozzle-type ICD is
a function of flow rate as the fluid passes through restricting ports inserted into the basepipe or into the housing outside the basepipe. As Bernoulli’s principle states, the pressure drop through a port increases as the square of the fluid-flow velocity, which increases as the port opening diameter decreases. Nozzle-based ICDs are self-regulating com-
pletion components. That is, given the uncer- tainty of permeability variations along the horizontal section of the wellbore, each ICD joint will behave independently of the local heteroge- neity and fluid type, which may change over time. The former may occur because of compaction or subsidence around the wellbore, and the latter as a result of the inevitable influx of water or gas. As fluids more mobile than oil, such as water
or gas, flow into the wellbore at higher velocities than that of oil, backpressure at the point of ingress increases. This slows the flow of forma- tion fluids through high-permeability intervals or streaks, preventing water or gas from reaching the wellbore ahead of reserves in less permeable sections of the formation.
5. Alkhelaiwi FT and Davies DR: “Inflow Control Devices: Application and Value Quantification of a Developing Technology,” paper SPE 108700, presented at the International Oil Conference and Exhibition in Mexico, Veracruz, Mexico, June 27–30, 2007.
6. Al Arfi SA, Salem SEA, Keshka AAS, Al-Bakr S, Amiri AH, El-Barbary AY, Elasmar M and Mohamed OY: “Inflow Control Device an Innovative Completion Solution from ‘Extended Wellbore to Extended Well Life Cycle’,” paper IPTC 12486, presented at the International
Helical devices force the fluid to flow through
channels that have a preset diameter and length. The differential pressure provided by these devices is determined by friction against the channel surface and is a function of the flow rate and fluid properties.6 This viscosity sensitivity may result in ineffi-
ciencies, however, when backpressure at break- through streaks is not significantly greater than that in areas producing oil that has lower viscos- ity because of entrained water and gas. Orifice ICDs are similar to nozzle-based
OSWIN09/10—Rick, story #2—Figure 04A
devices. Backpressure is generated by adjusting the number of orifices of known diameter and flow characteristics in each tool. The orifices are inserted in a jacket around a basepipe. Another option consists of an annular chamber on a stan- dard oilfield tubular. The reservoir fluid is pro- duced through a sand screen into a flow chamber from which it then flows through parallel tubes to the production string. Like helical-channel ver- sions, these tubular ICDs also rely on friction to create a pressure drop that is determined by the tube’s length and inside diameter. Some recently introduced ICDs are best described as tube- channel and orifice-nozzle combinations. Some wells may benefit from a recent ICD
innovation with a valve that reacts to an upstream or downstream change in pressure. The autono- mous ICD adjusts the flow area when the pres- sure differential across it changes.
Petroleum Technology Conference, Kuala Lumpur, December 3–5, 2008.
7. Maggs D, Raffn AG, Porturas F, Murison J, Tay F, Suwarlan W, Samsudin NB, Yusmar WZA, Yusof BW, Imran TNOM, Abdullah NA and Mat Reffin MZB: “Production Optimization for Second Stage Field Development Using ICD and Advanced Well Placement Technology,” paper SPE 113577, presented at the SPE Europec/EAGE Annual Conference and Exhibition, Rome, June 9–12, 2008.
All ICDs are permanent well components and
are rated by their flow resistance. Essentially, the rating signifies the total amount of pressure drop created across the device with a reference fluid property and flow rate. Nozzle- and orifice-type devices enjoy an advantage over channel ICDs: The nozzle size and therefore the ICD rating can be adjusted easily at the wellsite, before deployment, in response to real-time drilling information. The designs of ICDs are typically based on predrilling reservoir models, and changing the rating of channel- or tube-type ICDs is more difficult, time- consuming and not easily done on location.
Modeling: Static and Dynamic Historically, nozzle-type ICDs have been designed using a ratio of the pressure drop at the device inlet as calculated by Bernoulli’s equation to the average formation drawdown pressure derived from Darcy’s equation. When this ratio is close to unity, the ICDs are self-regulating. The designs based on these assumptions are
simple and effective in horizontal wells with rela- tively high productivity indexes (PIs) and mini- mal flow restrictions. The same number and size of ICD nozzles are assigned to each joint of tubing from toe to heel. This approach usually improves flow uniformity through the reservoir, counters much of the heel-toe effect and balances flow from heterogeneous zones. But these goals may be achieved at the cost of
overly restricting the flow from high-permeabil- ity, high-rate oil zones. Additionally, this method eliminates flexibility for zonal control and does not include the effects of variation in zonal poros- ity thickness, saturation and oil/water contacts. For more-precise designs, engineers can turn
to modeling using tools such as the Schlumberger ICD Advisor software. Using steady-state systems, the experts model wellbore hydraulics to deter- mine tubing and annulus flow, flow direction and completion-specific flow correlations. Reservoir flow is determined through PI models. Incorporating data from offset wells, LWD
tools, geology and other sources, engineers opti- mize well designs by determining near-wellbore performance at a specific time. They test various scenarios and completion designs to balance flow, decrease water cut, control gas/oil ratios and, by varying the number of isolation packers per well section, verify the effects of annular compart- mentalization (next page, top right). In doing so, they are determining the impact of packer den- sity on production in the presence of ICDs. Finally, they determine the number and sizes of nozzles to be deployed in each compartment.
32
Oilfield Review
Production rate per length, bbl/d/ft
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