Inflow Control Devices—Raising Profiles

30 Oilfield Review

Inflow Control Devices—Raising Profiles

Maximizing reserves recovery using horizontal wells requires management

of fluid flow through the reservoir. One increasingly popular approach is to use

inflow control devices that slow water and gas encroachment and reduce the

amount of bypassed reserves.

Tor EllisMarathon Petroleum Company (Norway) LLCStavanger, Norway

Alpay ErkalHouston, Texas, USA

Gordon GohKuala Lumpur, Malaysia

Timo JokelaSvein KvernstuenEdmund LeungTerje MoenFrancisco Porturas Torger SkillingstadPaul B. VorkinnStavanger, Norway

Anne Gerd Raffn Abingdon, England

Oilfield Review Winter 2009/2010: 21, no. 4. Copyright © 2010 Schlumberger.For help in preparation of this article, thanks to Ewen Connell, Rosharon, Texas; and Mary Jo Caliandro, Sugar Land, Texas.ECLIPSE, PeriScope, Petrel, ResFlow and ResInject are marks of Schlumberger.

1. Al-Khelaiwi FT, Birchenko VM, Konopczynski MR and Davies DR: “Advanced Wells: A Comprehensive Approach to the Selection Between Passive and Active Inflow Control Completions,” paper IPTC 12145, presented at the International Petroleum Technology Conference, Kuala Lumpur, December 3–5, 2008.

2. Raffn AG, Zeybek M, Moen T, Lauritzen JE, Sunbul AH, Hembling DE and Majdpour A: “Case Histories of Improved Horizontal Well Cleanup and Sweep Efficiency with Nozzle-Based Inflow Control Devices in Sandstone and Carbonate Reservoirs,” paper OTC 19172, presented at the Offshore Technology Conference, Houston, May 5–8, 2008.

3. Wellhead penetrations are holes in the wellhead through which power cables and hydraulic lines must pass to reach a device downhole. The number that can be drilled is limited by surface area and by the amount of material that can be removed from the wellhead without compromising its integrity.

4. Jokela T: “Significance of Inflow Control Device (ICD) Technology in Horizontal Sand Screen Completions,” Bachelor thesis, Det Teknisk-Naturvitenskapelige Fakultet, Stavanger, May 30, 2008.

> Heel-toe effect. Pressure losses along a horizontal wellbore in a homogeneous formation cause the flowing tubing pressure to be lower at the well’s heel than at the toe. In time, and long before oil (green) from sections near the toe arrives at the wellbore, water (blue) or gas (red) is drawn to the heel (top), resulting in an early end to the well’s productive life. Inflow control devices inside sand screen assemblies equalize the pressure drop along the entire length of the wellbore, promoting uniform flow of oil and gas through the formation (bottom) so that the arrivals of water and gas are delayed and simultaneous.

OSWIN09/10—Rick, story #2—Figure 02

Heel Toe

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Extended-reach and multilateral horizontal drill-ing techniques significantly increase wellbore/ reservoir contact. This augmented contact allows operators to use less drawdown pressure to achieve production rates equal to those of conventional vertical or deviated wells. The ability to optimize results from these standard configurations through better reservoir fluids management has been greatly enhanced by the development of remotely operated inflow control valves and chokes. These devices enable engineers to adjust flow from indi-vidual zones that are over- or underpressured or from those producing water or gas that may be det-rimental to overall well productivity.

Long sections drilled horizontally through a single reservoir, however, present a different set of challenges. In homogeneous formations, sig-nificant pressure drops occur within the open-hole interval as fluids flow from TD toward the heel of the well. The result may be significantly higher drawdown pressures at the heel than at the toe. Known as the heel-toe effect, this differ-ential causes unequal inflow along the well path and leads to water or gas coning at the heel (previous page). A possible consequence of this condition is an early end to the well’s productive life and substantial reserves left unrecovered in the lower section of the well.

Water or gas breakthrough anywhere along the length of the wellbore can also result from reser-voir heterogeneity or from differences in distances between the wellbore and fluid contacts. Pressure variations within the reservoir caused by reservoir compartmentalization or by interference from production- and injection-well flow can also lead to early breakthrough.1 Carbonate reservoirs, because they tend to have a high degree of fractur-ing and permeability variation, are especially vul-nerable to uneven inflow profiles and accelerated water and gas breakthroughs.2

Many completions designed for long-reach wells include sand control systems. If these com-pletions do not have isolation devices such as packers, annular flow can lead to severe erosion and plugging of sand screens. In the past such annular flow effects were countered with gravel packs or expandable sand screens. But gravel packs often reduce near-wellbore productivity. Expandable sand screens require complex instal-lation procedures and are prone to collapse later in the well’s life.

In traditional completions the solution to an increase in water or gas cut is to reduce the choke setting at the wellhead. This lowers draw-down pressure, resulting in lower production

rates but higher cumulative oil recovery. However, this simple solution generally does not work in wells drilled at high angles.

In wells completed with “intelligent” technol-ogy, operators may shut off or reduce flow from offending zones using remotely actuated down-hole valves. But horizontal wells designed to opti-mize reservoir exposure are often poor candidates for such strategies. Extremely long wells often have many zones. The limit on the number of wellhead penetrations available may render it impossible to deploy enough downhole control valves to be effective.3 Additionally, such comple-tions are expensive, complex and fraught with risk when installed in long, high-angle sections.

As a consequence, operators often choose to produce these multiple-zone wells using isolating devices such as swellable packers. To mitigate crossflow and to promote uniform flow through the reservoir, they have turned to passive inflow control devices (ICDs) in combination with swellable pack-ers. By restraining, or normalizing, flow through high-rate sections, ICDs create higher drawdown pressures and thus higher flow rates along the bore-hole sections that are more resistant to flow. This corrects uneven flow caused by the heel-toe effect and heterogeneous permeability.

Whether intended for injection or production, ICDs have applications in horizontal and devi-

ated wells and in several types of reservoirs.4 These devices are usually part of openhole com-pletions that also include sand screens. In addi-tion, ICD completions often use packers to segment the wellbore at points of large permea-bility contrast. This strategy combats water con-ing or gas cresting through fractured zones, halts annular flow between compartments and allows for isolation of potential wet zones.

ICDs are also effective in reservoirs where their ability to regulate inflow rates creates a suf-ficient pressure drop at the toe of the wellbore for the reservoir fluid to flow or lift filtercake and other solids to the surface.

This article describes various ICD designs and how they are modeled to suit particular applications. Case histories from Asia, the North Sea and the Middle East illustrate how these pas-sive devices enable operators to increase well life and ultimate recovery.

Velocity ControlInflow control devices are included in the hard-ware placed at the formation/borehole interface. They use a variety of flow-through configurations including nozzles, tubes and labyrinth helical channels (above). These devices are intended to balance the well’s inflow profile and minimize annular flow at the cost of a limited, additional

> Leading ICD types. Fluid from the formation (red arrows) flows through multiple screen layers mounted on an inner jacket, and along the annulus between the solid basepipe and the screens. It then enters the production tubing through a restriction in the case of nozzle- and orifice-based tools (top), or through a tortuous pathway in the case of helical- and tube-based devices (bottom).


Nozzle-Type ICD

Helical-Channel ICD

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32 Oilfield Review

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.

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 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.

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 DynamicHistorically, 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.

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

> 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.

OSWIN09/10—Rick, story #2—Figure 04A

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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.

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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 SpotThe 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.

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—

> 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%.


Oil Rate,bbl/d

Gas Rate,Mcf/d

Water Rate,bbl/d

Water Cut,%

BHP,psi

7,759

Open hole

698 2,411 23.7 3,794

3 x 4 mm, second joint

8,821 798 1,263 12.5 3,752

3 x 4 mm, joint

9,290 837 762 7.6 3,740

>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.)


–4,000

–3,875

–3,750

Gas zone

A

B

Oil zone Water zone

2,500

m0 750

ft0

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34 Oilfield Review

the PeriScope bed boundary mapper—was used to steer a smooth wellbore trajectory.

The longer lateral came online without the assistance of gas lift at 2,300 bbl/d [366 m3/d] of oil and a water cut of about 10%. This level of water production was expected from mobile water in the oil rim and is not associated with breakthrough from the water leg. The second well, drilled updip from the first, required gas lift to clean up and initially produced about 1,900 bbl/d [302 m3/d] with 20% water cut.

Production from both wells compared favor-ably with that from other deviated wells in the area drilled conventionally through the stacked sands of the field. However, even including costs of the additional technology—rotary steering sys-tem, LWD and ResFlow ICDs—the overall project cost was 15% less than it would have been using traditional well construction methods. In addi-tion, increased sweep efficiency gained by well placement and ICDs has increased the asset value by an estimated 100,000 bbl [16,000 m3] of oil.

Critical ComponentsBesides their ability to enhance drainage effi-ciency and boost cumulative oil recovery, ICDs offer the industry relatively inexpensive, low-risk components for technology-driven strategies. They can be easily added to development programs that include sand control and horizontal wells.

In the Norwegian sector of the North Sea, engi-neers at Marathon Petroleum Company (Norway) LLC concluded that the recoverable reserves in the relatively thin oil columns of the Alvheim and Volund fields were directly and consistently linked to the amount of net pay exposed to the wellbore (left). To establish maximum contact, Marathon therefore drilled single-, dual- and trilateral wells with horizontal sections ranging in length from 1,082 to 2,332 m [3,550 to 7,651 ft].

The Marathon team realized that to fully exploit the benefits of the correlation of recover-able reserves to net feet of reservoir contact, it was important that the entire length of the comple-tions contribute to production. Early in the project they decided to use both ResFlow nozzle-type ICDs and helical-type ICDs in all production wells—a total of 10 wells at Alvheim and 1 at Volund.

As a result of this technology-based approach and the favorable geology, Marathon has increased its booked reserves at Alvheim from 147 million to 201 million bbl [23 million to 32 million m3] of oil and from 196 to 269 Bcf [5.5 billion to 7.6 billion m3] of gas.

The fields have been in production less than two years, and the completions include numerous technologies, making it difficult to attribute specific results to a single methodology. However, overall water production at the Alvheim floating, production, storage and offloading (FPSO) facility is less than originally expected. A good example is the 24/6-B-1CH well, which has a 13-m [43-ft] oil column and an active aquifer. The well has been produced at higher rates than originally planned without significant onset of, or increase in, water production (left). Both these outcomes, though their causes are inconclusive, suggest ICD success in maintaining an even flow profile.

When one completion planned as a single lat-eral evolved to a trilateral, engineers also learned a valuable lesson concerning planning for the use of ICDs and multilateral installations. Because the actual completion departed from the original plan, the flow rate was different than predicted. The ICDs chosen for these installations were of a design type that could not be readily changed, and thus optimized, on location. The result was gas and water coning earlier than expected in both laterals.

> Layout of Alvheim and Volund fields in the Norwegian area of the North Sea. [Courtesy of Marathon Petroleum Company (Norway) LLC.]


Boa

Volund

Kneler B

Southriser base

West riserbase

East riserbase

Alvheim FPSO

Kneler A

East Kameleon

Vilje

Production line

Gas lift line

Water injectionand disposal line

Umbilical

> Production improvements. In Well 24/6-B-1CH of the Alvheim field, the 13-m oil column with an active aquifer was produced at a higher drawdown than originally planned. As shown in the graph, the resulting higher production volumes were achieved without significantly increasing water cut over predicted values, which is indicative, if not conclusive, that an even inflow profile was achieved.


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8. Krinis D, Hembling D, Al-Dawood N, Al-Qatari S, Simonian S and Salerno G: “Optimizing Horizontal Well Performance in Nonuniform Pressure Environments Using Passive Inflow Control Devices,” paper OTC 20129, presented at the Offshore Technology Conference, Houston, May 4–7, 2009.

9. Krinis et al, reference 8.

Recently, a different operator expanded on the application of ICD completions, not to coun-ter the effects of uneven inflow profiles but to counter uneven pressure profiles. In one horizon-tal well extending more than 5,200 ft [1,600 m] through a high-permeability reservoir in a large Middle East field, the pressure differential between heel and toe was 200 psi [1.4 MPa] with the higher pressure at the heel.8

An initial production log confirmed what was expected given the pressure profile: A downward crossflow of fluids from heel to toe was detected during a shut-in logging pass. In addition, produc-tion logging measurements acquired while the well was flowing showed water moving downward from the heel and oil flowing to the surface. Logs also indicated production was coming from only the first 10% of the lateral.9

Based on the results of static modeling, the operator recompleted the well with 22 ResFlow ICDs and, to segment the well, seven swellable packers on the production string. Logs acquired after recompletion indicated that crossflow had been eliminated and production was coming from the entire lateral. Water cut was reduced from 30% to less than 10%, and the actual inflow profile matched that predicted by the static ICD model (above right).10

A Clean StartPredictably, it has been observed that the differ-ence in pressure drops between the heel and toe caused by friction losses in an openhole horizon-tal well increases with wellbore length. This disparity can lead to the filtercake being prefer-entially lifted from the wellbore wall at the heel and to poor inflow performance caused by corre-spondingly higher skin at the toe.

Studies have shown that in relatively high-permeability environments, the best cleanup results—removal of filtercake after drilling or completion—are obtained through proper chem-ical treatment and extended flowback with high rates.11 In 2006 Saudi Aramco completed two test wells equipped with ICD systems, one in a sand-stone formation and the other in carbonate rock. In the sandstone there were concerns over water and gas coning through high-permeability streaks, and the operator sought to decrease the impact of the heel-toe effect to improve cleanup and sweep efficiency. The 8½-in. openhole com-pletion included 5½-in. screens with ResFlow ICD nozzles on every joint of tubing. For compart-mentalization and better inflow control, small, swellable elastomer packers were placed on every second joint. The horizontal section was 2,540 ft [775 m] long.

The well was produced at 6,000 to 7,000 bbl/d [953 to 1,113 m3/d] for 4 months. A production log was then acquired. The log data, as well as the inability to get the tool within 650 ft [198 m] of TD because of solids-laden mud filling the toe of the wellbore, indicated the well had not cleaned up despite the prolonged flow period.

The flow rate was then increased to 9,000 to 10,000 bbl/d [1,430 to 1,590 m3/d] for 4 h and the

well was logged again. The new data indicated an improved flow profile and the tool was able to travel an additional 350 ft [106 m]. Four hours later, the logging tool was run again, this time to within 50 ft [15 m] of TD (below). The rate was reduced to the original 6,000 to 7,000 bbl/d and data from the final logging run indicated a permanent change had been made to the inflow profile.

> Inflow profile from production log measurements. After installation of ICDs and swellable packers, production logging tools were run to acquire an inflow profile along the length of the well at low, medium and high flow rates. The inflow profile shown was obtained with the well flowing at the medium rate. Crossflow evident in earlier logs has been eliminated and flow contribution is evident from the entire lateral. The actual inflow profile (green) was very close to the simulated one (red). (Adapted from Krinis et al, reference 8.)


ICD completion actual flow profile

Simulated flow profile

1 ICD

Heel Toe

1 ICDICD

2 ICDs 2 ICDs 3 ICDs 3 ICDs 4 ICDs 5 ICDs

Prod

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Swellable packer

Measured depth

10. Krinis et al, reference 8.11. Shahri AM, Kilany K, Hembling D, Lauritzen JE,

Gottumukkala V, Ogunyemi O and Becerra Moreno O: “Best Cleanup Practices for an Offshore Sandstone Reservoir with ICD Completions in Horizontal Wells,” paper SPE 120651, presented at the SPE Middle East Oil and Gas Show and Conference, Bahrain, March 15–18, 2009.

> Cleanup through higher rates. After the logging tool failed to reach TD and log data indicated no production contribution from the toe after an initial flow period of 4 months (red), the rate was increased to about 9,000 to 10,000 bbl/d for 4 h and the production log was rerun. Log data yielded an improved flow profile, and the tool was able to travel an additional 350 ft (gray). Four hours later, the logging tool was run to within 50 ft of TD (green). The rate was returned to about 6,000 to 7,000 bbl/d, and log data demonstrated a permanent change had been made to the inflow profile (blue). (Adapted from Sunbul et al, reference 12.)


Measured depth, ft11,7009,000 9,300 9,600 9,900 10,200 10,500 10,800 11,100 11,400

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36 Oilfield Review

Engineers suspected that the higher rates required to clean up the entire production interval had exacerbated the heel-toe effect in the tradi-tional openhole completions. Modelers matched the production log data to a static reservoir simu-lation and replaced the ICD completion in the simulation with a standard screen completion. They then increased the rate in the standard screen completion to 15,000 bbl/d [2,400 m3/d].

That simulation indicated an extreme heel-toe effect: The toe was contributing only 25% as much production as the heel. By contrast, simu-lated ICD completions with 15,000-bbl/d rates showed better balance of the inflow, including much higher contribution from the toe.12

These findings are significant in that they show ICD completions allow extended well lengths in both these formations without compro-mising the balancing effect or cleanup efficiency in the lower sections of the wells. That result allows the operator to contact more formation with fewer wellbores without fear of sacrificing cumulative production.

Reversing DirectionThough they are called inflow control devices, ICDs are also used to manage fluid outflow in injection wells. In some cases modeling reveals that it is more effective to place ICDs in the injec-tor well than in the producer. And in many instances installing the devices in both the injec-tor and producer wells is the best option.

Injector wells often penetrate and give pres-sure support to several reservoir intervals with varying characteristics. To avoid water break-through at production wells, reservoir engineers

designing injection projects must consider per-meability contrasts, heel-toe effect, formation damage, creation of thief zones and injectivity changes at the wellbore.13

Just as they do with inflow control, ICDs address these challenges by balancing fluid out-flow along the entire length of the injection well-bore. If the well has a high-permeability streak, the ICD self-regulating feature prevents a signifi-cant increase of local injection rate. This ability to automatically control fluid mobility results in better water distribution and pressure support and thus enhanced areal and vertical sweep of oil reserves in all zones. It also delays water break-through, and because ICDs can control injection pressure and rate, there is minimal risk of near-wellbore fracturing.

These capabilities matched the management goals of the Statoil team planning the 2004 devel-opment of the Urd field—a satellite producing to the Norne FPSO vessel in the North Sea. Placed on production in 2005, the Urd oil field contains two heterogeneous structures: Svale and Stær, which are 4 and 9 km [2.5 and 5.6 mi], respectively, from the main field. The field was developed using three subsea templates and pipelines for oil production, water injection and gas lift. Management goals for the ICD injection system included•optimizing pressure support and sweep effi-

ciency for all zones•delaying water breakthrough in high-permea-

bility connected zones •avoiding fractures that may dominate water

distribution.The Stær structure was completed with one

injector containing ICDs and two horizontal oil producers containing intelligent technology for control of three zones. The reservoir is divided

into two segments; the injector and producer are located in Segment 1 and the second oil producer in Segment 2.

The injector is a vertical well drilled through the Not, Ile, Tilj and Åre 2 Formations and pro-vides sweep and pressure support for two hori-zontal producers. About 250 m [820 ft] deep, the injection well is an openhole completion with ResInject injection control devices, sand screens and a pack of resin-coated gravel to prevent annular flow.

Engineers from Reslink and Statoil designed the system. They modeled injection rates expected for three zones using different comple-tion techniques: standard screens alone, ICDs of the same nozzle size and number of nozzles per joint, and different numbers of ICDs per joint (left). The team chose to use the same nozzle configuration along the entire wellbore instead of specific ICD nozzle sizes and numbers for each zone. This choice reflected the fact that while dif-ferent designs in each zone achieved target injec-tion rates, simulations supported maximum injection rates in the upper zones.14

These simulations were run to evaluate the economics of using ICD injectors on Stær and to select the nozzle design. Two static near-wellbore simulations were used to compare water distribu-tion: The first was based on injection into the matrix, including its permeability variations, and the second considered injection into a frac-tured zone.

In the first case, the upper, high-permeability zone received an uneven share of the injected water. However, with ICDs, peak outflow was reduced by 50% and zones with lower permeabil-ity received more water. For the second static model, a 12-m [39-ft], 20-D layer was added to

12. Sunbul AH, Lauritzen JE, Hembling DE, Majdpour A, Raffn AG, Zeybek M and Moen T: “Case Histories of Improved Horizontal Well Cleanup and Sweep Efficiency with Nozzle Based Inflow Control Devices in Sandstone and Carbonate Reservoirs,” paper SPE 120795, presented at the SPE Saudi Arabia Section Technical Symposium, Alkhobar, Saudi Arabia, May 10–12, 2008.

13. Raffn AG, Hundsnes S, Kvernstuen S and Moen T: “ICD Screen Technology Used to Optimize Waterflooding in Injector Well,” paper SPE 106018, presented at the SPE Production and Operations Symposium, Oklahoma City, Oklahoma, USA, March 31–April 3, 2007.

14. Raffn et al, reference 13.15. Tachet E, Alvestad J, Wat R and Keogh K: “Improve

Steam Distribution in Canadian Reservoirs During SAGD Operations Through Completion Solutions,” paper 2009-332, presented at the World Heavy Oil Congress, Porlamar, Venezuela, November 3–5, 2009.

16. Fram JH and Sims JC: “Addressing Horizontal Steam Injection Completions Challenges with Chevron’s Horizontal Steam Test Facility,” paper 2009-398, presented at the World Heavy Oil Congress, Porlamar, Venezuela, November 3–5, 2009.

17. Fram and Sims, reference 16.

> Optimizing injector ICD design. The injection rates used in the different completion scenarios of the Stær structure demonstrate that the injectors can be optimized based on permeability and nozzle design to obtain the desired rates in each zone. (Adapted from Raffn et al, reference 13.)


Zone 1800 to 1,800 mD

5,800 4,604 3,570 3,500

StandardScreen

ICD withSame Nozzle

Size, 1.2cm/joint,

in All Zones

ICD withDifferent

Configuration

Nozzle Size

Target Rate,m3/d

Zone 2200 to 500 mD

748 1,233 820 800

Zone 3100 to 2,000 mD

961 1,677 3,128

0.9 cm/joint

0.7 cm/joint

2.2 cm/joint

3,200

Total injection rate, m3/d 7,509 7,514 7,518 7,500

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Winter 2009/2010 37

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 FutureThe 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. —RvF

>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.)


1,000,000800,000600,000Cumulative oil production, m3

400,000200,0000

80

70

60

50

40

30

20

10

0

Wat

er c

ut, %

Production historyModeled standard completion,high-permeability channelsModeled standard completion,no high-permeability channels

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Documents

Inflow Control Devices—Raising Profiles