September 2020

Autonomously reducing water production and improving oil recovery in Oman

Effective management of reservoir sweep, with regard to wellbore influx, is an inherent issue affecting horizontal well lengths. As an active, self-regulating technology, autonomous inflow control devices respond to viscosity changes to choke water and gas more effectively, increasing production and sustainability.
Osama Abazeed / Tendeka

In recent years, water production and integrity issues have been the main challenge in high-viscosity fields in the South of Oman salt basin. The complex, heavy oil fields started production in 1985 and have produced heavy oil (21oAPI) from more than 1,000 well penetrations into the sandstone reservoirs, of which 80% are horizontal.

Historical performance of the fields was analyzed from 2015, to characterize rock behavior (matrix behavior, conductive streaks, fractures, faults, etc).1 This showed that water cut progression was naturally-occurring in fractures, which are limited in length and not vertically extensive, creating unexpectedly higher initial water production.

From first production until 2004, the field’s water cut gradually increased from 0% to 30%, with an average of 20% initial water cut in this 10-year period. However, after 2004, the average initial base sediment and water (BSW) of new wells in the field jumped to 85%. Even wells with initially low BSW soon developed a very high water cut within two to three months.

It was hence discovered that during the early stages of production, when the initial water cut shows matrix-like behavior, the bottom water is not in contact with the fracture network. However, after years of production and rise of the water table, the fracture behavior became dominant, as the water came into contact with the small vertical fractures.

To identify causes and recommend mitigations, a major operator in Oman conducted several multi-disciplinary studies. A number of options, including precise swellable packer placement and smart well completion technologies, were investigated to stop water encroachment into the wells and, ultimately, improve productivity.


Fig. 1. (left) AICD flow path and disk position with oil; and (right) AICD flow path and disk position with water.
Fig. 1. (left) AICD flow path and disk position with oil; and (right) AICD flow path and disk position with water.

Historically, it has been noticed that some completed wells produce with high water cuts initially, and this continues to increase with time as the drawdown increases. This is mainly attributed to the coning effect taking place at the producing wells, where water bypasses oil and goes directly for the producing intervals.2

Also, one of the limiting factors affecting the length of horizontal wells has been the effective management of reservoir sweep with regard to wellbore influx.3

The added benefit of greater reservoir contact is met with increased differential drawdown across the well length, and a greater tendency to cut across heterogeneous formation with varying permeability. A further, important aspect of heavy oil is its viscosity, as this can directly impact the reservoir’s recovery and productivity. The viscosity difference between heavy oil and water creates an unfavorable mobility ratio, which generates quicker water breakthrough. This allows water to flow much faster through the reservoir and into the wellbore, displacing the oil production from producing zones.

Fig. 2. Construction of RCP-type AICD ©Tendeka.
Fig. 2. Construction of RCP-type AICD ©Tendeka.

For many years, inflow control devices (ICDs), which restrict flow by creating additional pressure, have been used to mitigate
this problem. They are, however, passive in nature, and, once installed, cannot be adjusted. In the event of water or gas breakthrough in an oil well, the disadvantage of the passive ICD becomes evident, as the well can be quickly overtaken by the breaking fluid where mobility contrasts exist.

Autonomous ICDs (AICDs) are, however, self-regulating and are classed as active. Unlike their passive counterparts, which react only to fluid density changes, they respond to viscosity changes to choke water and gas more effectively. In a compartmentalized wellbore, the devices increase oil production, leading to greater recovery by reducing the flow from compartments producing higher gas or water fraction.

Independent global completions service company, Tendeka, has worked with the operator in Oman for nearly 20 years, which currently has around 209 producing oil fields and more than 8,000 active wells.

In 2018, to control the flow of fluids and reduce unwanted water production in the South of Oman salt basin, the service company designed and deployed the AICD completion to be piloted in two newly drilled horizontal wells, in two of the basin’s fields. The reservoir contains viscous oil (400-600 cp) and exhibits high inflow potential, due to favorable rock properties and strong water drive. Each well was completed with AICDs along a completed lateral length of 500 m, divided into several compartments using swellable packers.

Fig. 3. AICD unit mounted into sand screen joints.
Fig. 3. AICD unit mounted into sand screen joints.

AICD technology is comprised of mechanical devices that are installed with the sand face completion, Fig. 1. As an active flow resistance element distributed along the length of the horizontal wellbore section, the device can delay and reduce the proportions of water breakthrough. Due to the real-time reaction to the local fluid dynamics within the tool, it works by imposing a relatively strong resistance for low-viscous fluids over high-viscous oil. By restricting the flow of water in high water cut zones, it enables greater drawdown of the reservoir in high oil saturation zones, thereby reducing water cut and improving oil recovery for the overall well.

To improve crude production, there must be a variation in the oil saturation or oil cut along the wellbore’s length. In other words, what comes in must go out. Therefore, if the whole length of the wellbore is at 90% water cut, the AICD cannot make an improvement. AICDs react to the properties of the fluids passing through them and can act as an “insurance policy” on well performance uncertainty.

An AICD operates without the need for human or surface interventions and electric or hydraulic power, Fig. 2. Once the device is installed, and the completion is in the ground, no interpretations, actions or decisions are required.

The AICD valve is assembled as part of the sand screen joint, Fig. 3. The flow path from the reservoir is marked by arrows. The reservoir fluids enter the completion through the sand screen filter and flow into the inflow control housing, where the AICD is mounted. The fluids then flow through the AICD and into the production stream, and flow to surface, together with the production from the rest of the screens.


Improved understanding of AICDs through single- and multi-phase testing has allowed for the creation of mathematical models, making it possible to upscale/downscale these devices for changing conditions.

For creation of performance curves for any downhole fluid properties, a multi-step approach for design and optimization of an AICD completion program should be followed. This involves:

  1. Collation of customer reservoir data and performance requirements
  2. Design of the AICD to suit the reservoir flow characteristics
  3. Creation of initial fluid flow performance curves to compare with a passive ICD design
  4. Generation of AICD performance coefficients for input into linear and non-linear regression simulators
  5. Quality check of the design’s regression coefficients for gas control accuracy.

Typically, the type of customer reservoir data required to create an optimized AICD design is:

  • Live oil/gas/water densities and viscosities
  • Expected production rates (oil/gas/water) without ICD completion (initial/mid-life/late-life)
  • Initial expected drawdown
  • Well length.

These data are input into the design and simulator software, to aid creating an optimum AICD design. A unified approach to AICD modeling is paramount.

Unless the bottomhole viscosity of oil and water is the same, an AICD should always outperform a passive ICD system. Ensuring sufficient hydraulics capacity for total liquids over the life of the well is important when running these simulations.


In 2018, AICD performance was piloted in two newly drilled horizontal wells, in two fields of the South of Oman salt basin.

Typical well performance of the first field (field A) was mostly water with 600 m3/day of gross liquids produced. It had suffered from high water cut since day one, as the average BSW for the field is 96% to 97%. Normally, this field would be completed with 4.5-in. wire-wrapped screen (WWS), with swellable packers to isolate the major fracture.

The first AICD trial was performed in one of five wells (A-111) drilled in this field. It showed excellent performance, where the water cut remained below 5% with a 50-m3/d oil gain. The well was completed with seven compartments, with 4.5-in. blank pipe, 14 AICDs and seven swellable packers. This was in comparison to 98% of the offset wells.

The second well is B-130 in field B. The typical performance of this new well is 10-20 m3/day of oil with BSW of 75% to 90%. The completion of the well is normally 7-in.WWS, with or without packers, dependent on the well’s condition. This was completed with five compartments with 7-in. blank pipe, 13 AICDs and five swellable packers. The well test results showed 90 m3/day, net oil, and <5% water cut.


To control the water production for existing wells, the normal practice is to isolate some compartments from the horizontal section mechanically or, in some cases, by chemical water shut-off (WSO). To conduct well intervention, a hoist is required for both procedures:

  • The chemical method was used to restrict or plug the highly permeable zone that has high water influx
  • The mechanical WSO prevents production from the selected zone by either using cement or a specific device.

A good interpreter of the fractures in horizontal wells can greatly help in the identification of the expected high-water sections. However, this method has many uncertainties, due to the reservoir complexities. Mechanical WSO installed in different ways, for example, depends on the orientation of the well and the crossed lithology.

The most common mechanical WSO is by segmenting the wellbore with swellable packers and WWS. After a period, the flow can be shut off in the horizontal section from the heel, mid or toe sections.

As fields A and B have a high water cut of more than 98%, different WSO methods were applied with a 50% success factor, as outlined below:

  • 120 m3/day to 58 m3/day
  • ~100% net oil gained (17 m3/day to 29 m3/day)
  • ~300% reduction in water production (92 m3/day to 29 m3/day).

The trials on new and existing wells in the South Oman fields have shown that the AICD application is an economical solution to restrict water production and gain oil for a viscous oil reservoir. It is also a very effective solution for water shut-off, compared to conventional completions with mechanical or chemical water shut-off.

Essentially, the higher the number of compartments, the more efficiently that AICDs perform to restrict water production and gain oil. This also results in a clearer contrast in viscosity between the fluid we want to produce (oil) and the fluid we want to control (water or gas).


Fig. 4. SwellRight swellable packers are a permanent packer solution, suitable for many applications where a pressure seal or zonal isolation is required.
Fig. 4. SwellRight swellable packers are a permanent packer solution, suitable for many applications where a pressure seal or zonal isolation is required.

Tendeka is also working closely with the operator to provide swellable packers for long-term stability and reliability required to isolate producing zones. For instance, the retrievable SwellRight option (Fig. 4) has been designed to isolate the wellbore while enabling the easy removal of the entire assembly from the wellbore without any milling operations. This significantly helps reduce well construction costs, extend well life, and improve well integrity.

For high-pressure application, the advanced swell packers provide a cost-effective solution, with the high-pressure ratings achieved over a short element. By enabling operators to utilize smaller pup joints, this can effectively reduce the amount of rubber element required. It can be used in both horizontal and vertical wells.


As a result of the trials and further installations, the customer has identified AICDs as one of the key new technologies bringing value in their 2019 sustainability report, highlighting $50 million of added value, annually, across the company, to date.

Water production is an inevitable by-product of heavy oil production, requiring either a strong underlying aquifer, as described, or water injection into nearby wells to displace the oil through the reservoir. Reducing the amount of water produced per barrel of oil recovered reduces water handling costs and increases production efficiency. This is achieved through reduced power use for processing and pumping water into the reservoir, and reduced use of downhole pumps for oil and water production.

As the focus on sustainability in oil and gas production increases, the role of technology—such as AICDs that are an established means of increasing well productivity in complex reservoirs—will play a key role in achieving our sustainability goals.


  1. B. A. Voll et al, “Sustaining production by limiting water cut and gas breakthrough with autonomous inflow control technology,” paper SPE-171149-MS, 2014.
  2. A. Harrasi, et al, “More oil and less water: Heavy oil field application on the autonomous inflow control device (aicd) in long horizontal wells – A case study from South Sultanate of Oman,” paper SPE-193554-MS, 2019.
  3. A. Sivrikoz, et al, “Tackling high water production in Oman South fields with new technology,” paper SPE-193658-MS, 2018.
About the Authors
Osama Abazeed
Osama Abazeed is a Middle East Area manager with Tendeka. He received his degree from the University of Damascus (Syria) and has more than 16 years’ experience in multiple disciplines in the upstream industry. Prior to Tendeka, Mr. Abazeed was involved in various projects in downhole technology, wireline logging, perforation, reservoir characterization and completion, with great focus on the Middle Eastern region. He has published several technical papers.
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