Controlling sand output while increasing heavy oil production offshore China

Various challenges, including early water breakthrough and reduced oil recovery, are the result of variable reservoir characteristics, including the fluid and petrophysical properties, layer pressure, and fluid contacts in zones intersected by the horizontal wellbore. These difficulties can be mitigated by deploying advanced well completions to manage reservoir fluid influx toward the wellbore, and thereby optimize well performance.^1-7 In addition, several studies have proven the application of advanced well completions as a type of insurance policy against geological and dynamic reservoir uncertainties,⁸ to reduce the risk and variation in the expected oil production profiles.

In 2018,  CNOOC China Ltd._Shenzhen and global production optimization and advanced completion specialist, Tendeka, undertook an infill development campaign in a thin, heavy oil reservoir, in the South China Sea. The gravel-packed, heavy oil production well was expected to intersect heterogeneous formations with varying properties, resulting in an uneven reservoir influx toward the wellbore. In addition, water mobility in the reservoir was at least 150 times larger than oil mobility, and a strong aquifer was located near the well. The project, to mitigate the problems of uneven sweep and water production, involved the installation of autonomous inflow control devices (AICD) and a new generation of inflow control device (ICD).

BACKGROUND

Fig. 1. Structural contour and well position map.

The field is a low-amplitude fault anticline oil field, developed on the basement uplift, where the structure is relatively gentle, Fig. 1. With a horizontal length of 440 m, the well was drilled in a thin formation with an oil column of 4.5 m on average. The rock type is categorized as highly muddy with unconsolidated sandstone. The large contact area of horizontal wells makes the successful exploitation of these reservoirs feasible. However, the uneven production influx from the reservoir toward the well has been recognized as the main problem in managing the production of cold, heavy oil wells.

As the wells are traditionally completed with screens, gravel packs or slotted liners to control sand production, performing conventional intervention techniques to deal with excessive water production is a huge challenge. This is due to requirements to perform production logging testing (PLT), followed by squeezing cement or gel, setting plugs and isolating sections with blank straddles/packers. First, this does not guarantee to deliver the optimum solution, and second, it is associated with high cost, risk and limits, especially for offshore operations.

Deploying AICDs to manage the reservoir fluid influx toward the wellbore can mitigate such challenges and, therefore, optimize well performance. The active flow control device delivers a variable flow restriction in response to the properties of the fluid and the rate of flow passing through. As demonstrated by many case histories, the introduction of AICDs has proven successful in effectively controlling unwanted fluids. More than 70 successful AICD applications in heavy oil formations have been deployed worldwide.⁶

Fig. 2. Gravel packing fluid path with temporary bypass valve.

Advanced well completions. In many applications, ICDs/AICDs are deployed into weak sandstone reservoirs that are prone to failure and, consequently, sand production. Frequently, they are combined with a sand control solution. It is, therefore, best practice in sands with high fines content and/or poor sorting to control the sand, using gravel packing techniques. Gravel packing involves pumping a slurry of water and large sand particles/gravel into the annulus between the wellbore and the sand screen completion, and allowing the carrier fluid to return via the sand screens leaving the gravel in place.

In horizontal wells, this is commonly achieved, using a technique referred to as alpha-beta packing, whereby the slurry is initially pumped into the annulus at a velocity that allows gravel to drop out of the slurry and form a sand dune. The dune builds up from the heel of the well and travels toward the toe, with the height of the dune being determined by the fluid properties, gravel density and concentration, in addition to the annular velocity.

Once the toe of the annulus is reached, the gravel continues to pack the annular area in a returning or Beta dune that fills the annulus from toe to heel. As the Beta wave fills the annulus, the length of sand screen available for fluid return reduces, and the length of the return path increases, causing pressure to increase. Alternative techniques, such as viscose pack, forego the alpha wave formation, using only the return path described by the Beta wave process. During gravel packing, it is critical that the pressure caused by pumping fluids does not exceed the fracture strength of the formation, as this will prevent further packing of the well. The additional pressure drops imposed by the flow control devices make conventional gravel packing operations impractical.

Fig. 3. Principal components of the new AICD device.

The current methodology for gravel packing with ICD/AICDs in the well utilizes a multiple alpha wave technique, whereby at least one conventional stand-alone screen joint is deployed at the toe of the well to provide a return path during the build-up of the alpha wave. The flowrate is reduced progressively to maximize the dune weight until screen-out is observed. Once the gravel packing operation is complete, the stand-alone screen section at the toe is isolated before the well is placed on production. This technique does not allow a complete pack (reported efficiently between 72% and 81%) to be achieved, and will allow more gravel to build up around the zonal isolation packers (since the best practice is to maintain higher annular velocities to prevent gravel drop out around the packer). 

Furthermore, many heterogeneous reservoirs feature high loss zones or unstable shale sections, which require the use of shunt-tube screen technology to ensure a complete pack. This requires viscose pack techniques to be used. Consequently, this methodology is most applicable in unconsolidated sands, with high net-to-gross reservoirs, where borehole collapse will occur early in well life.

Fig. 4. Completion schematic for Well C2H.

One possible technique to provide sufficient flow path through the screen assembly is to integrate sliding sleeves into each screen joint, but in long lateral wellbores this may be prohibitively expensive and require multiple manual manipulations, as the wash pipe is retrieved. To solve this issue, the use of a temporarily bypass valve is recommended, to enable standard gravel packing operations to be performed with ICDs in the completion without significant additional cost, operational complexity or compromising production, Fig. 2. The dissolvable material is utilized with a valve located within the ICD/AICD housing to provide a high flow path from the annulus to the tubing during completion operations.

Innovative AICD technology. The FloSure AICD (Fig. 3) was introduced to function as a standard ICD, to provide a proactive solution and restrict the production of unwanted effluents with lower viscosity after breakthrough, such as water in heavy oil production (reactive solution). The AICD is typically incorporated as part of a screen joint, Fig. 4. Here, produced fluids enter the completion through the screen, and flow in the annular space between the screen and the unperforated base pipe into the AICD housing, where the device is mounted. Fluids then flow through the AICD into the interior of the production conduit, where they combine with the flow from other zones.

Fig. 5. Production profile for Well C2H.

As an active device that regulates the flow of fluids, usually by the conversion of potential energy (pressure), it is capable of modifying its control characteristics automatically in response to fluid properties flowing through. It generates a variable pressure drop, based on the size of the inlet nozzle, and on the gap created between a levitating disk and the top plate of the housing in which it is contained. Fluid flow enters the device through the nozzle at the top plate, impacts the disk, and spreads radially through the gap between the disk and the top plate, then discharges through several outlet ports in the body.

Due to its dimensions, the device can be threaded directly into the base pipe. It is possible to have up to four threaded ports compatible with AICDs, passive ICDs, chemical treatment valves or blanking plugs on each screen joint. This provides a high degree of flexibility for reacting to reservoir uncertainty after drilling and inventory flexibility, as the valve can be mounted or replaced any time, even at the rig.

Dynamic reservoir simulators are required to estimate the AICD’s production benefits over a well’s lifetime. As actual well trajectory and reservoir properties are rarely the same as planned, the actual well is simulated just after drilling with a static near-wellbore simulator to optimize placement of screens, blanks and swellable packers prior to completion.

Well completions and reservoir properties. Wells C1H (completed with gravel pack with stand-alone screens but no AICDs) and C2H are in the same reservoir formation, in the field. C1H is near the oil boundary of the main reservoir and is 400 m from C2H.

While the C2H well is quite similar to C1H, both in terms of reservoir properties and completions, it was chosen as the analogue well to observe the AICD performance. As shown in Fig. 5, the water cut of the C2H well at the initial stage of production was about 6%. It then increased rapidly to 80% in just three months and stabilized at 90%. This is in line with the performance of other wells in the field.

Fig. 6. AICD performance curve.

C1H was selected as a pilot well for further AICD applications in upcoming wells, in the field. The reservoir pressure in C1H is approximately 13.5 Mpa and border water aquifer supports the reservoir pressure for both C1H and C2H wells. The formation temperature is about 74°C, the formation thickness is 7.5 m with an average effective thickness of 4 m, and porosity is 26.6% (from logging interpretation). The average permeability is 514 mD, the average shale content is 13.6%, and the degree of heterogeneity is high. Also, the reservoir sand is unconsolidated and very loose, with a high shale content.

As the conventional completion method cannot restrain the influence of mud and sand migration on productivity, it was necessary to gravel pack the completion of the C1H well to prevent mud and sand plugging. A dual-trip completion was chosen to run for this well. This first allowed for gravel packing of the annular area between the screens and open hole and then retrofitting an inner string of AICD subs and zonal isolations inside the screens.

AICD completion design workflow. An extensive pre-drilling study, including static and dynamic well/reservoir modelling, was performed to investigate the value of using AICDs and to determine the strategy for the completion. The objective was to produce efficiently, a liquid production range of 500 to 3,000 bpd over the well’s lifetime.

Fig. 7. Completion schematic for Well C1H.

Within the short period in-between reaching targeted drilling depth and running the completion tally in the well, the interpreted real-time log data—i.e., saturation, permeability and caliper data, plus the drilled well trajectory—were used in a static wellbore modelling software to finalize the lower completion of the well. Figure 6 shows the predicted performance of AICDs for the fluid characteristics of the reservoir in a single-phase condition. It demonstrates that the AICD significantly distinguishes oil and water, due to its significant viscosity difference.

This modeling was involved in simulating several completion designs (various packer placements and AICD numbers) to optimize well performance. Placement of packers was crucial to the optimum AICD performance and, subsequently, the added value from the well,⁷ as only three packers were practically possible to install. The final design was an inner string completion comprising 20 AICDs on 27/8-in. subs (one per sub) at four zones, compartmentalized with three swellable packers to control water production. Figure 7 shows the design of an installed lower completion, the distribution of AICDs and packer locations.

Table 1. Performance of wells C1H and C2H after 365 days of production.

Final modeling was performed within the period between reaching target depth and running the completion. The performance of well C1H with the AICDs, which has been producing since December 2018, has resulted in a significant volume of oil while water cut is still below 20% after 12 months of production. This well has no problems with sand production, and it has successfully delivered a 200% increase in total oil production, compared to the offset well. Over the same period, the offset well with no AICD devices encountered water production in the first two weeks, and water cut has continued to increase to 88%.

Table 1 summarizes the total oil and water production for both wells. This shows a 200% increase in total oil production from well C1H, compared to well C2H with no AICDs. The C2H well has been in production for 645 days, with cumulative water production of 1.51 MMbbl, cumulative oil production of 0.23 MMbbl, and water content of 90.3%.

Table 2. Performance of Well C1H: prediction versus reality.

AICD well performance: predicated versus reality. The actual well trajectory and reservoir properties are rarely the same as planned. Therefore, the actual well performance would be different than the predicted profile. The modeling of prediction performance involves assuming several reservoirs and wellbore uncertainties, reservoir properties upscaling, simplification and estimations. Based on the authors’ experience and publicly available reports, the well performance prediction by reservoir simulation software is normally pessimistic compared to the actual well performance.^3,4,10

Table 2 and Fig. 8 compare the actual performance versus the predicted performance for well C1H (with AICDs). As shown, the C1H well performance is significantly better than predicted, as it has produced an average oil production rate of 713 bpd, which is 43% higher than the optimistic rate.

Fig. 8. Performance of Well C1H: prediction versus reality.

VALUE ADDED

In summary, the combination of AICD devices and gravel pack completions could effectively prevent sand production and control water in the field while improving oil well recovery rates, compared to analog wells. This would have guidance and reference significance for development of similar unconsolidated and high argillaceous heavy oil reservoirs and have extensive promotion value in the field. The project clearly demonstrates the possibility of a successful combination of AICD and gravel packs. AICD completions ensure a balanced contribution from all reservoir sections, while significantly limiting water production, with the gravel pack keeping the valves and the well safe from the impact of sand.

ACKNOWLEDGEMENT

This article is an abridged version of OTC paper 30403-MS, which was scheduled for presentation in Kuala Lumpur, Malaysia, August 17-19, 2020. The official proceedings were subsequently published online on Oct. 27, 2020.

REFERENCES

1. Dowlatabad, M. M., “Novel integrated approach simultaneously optimising AFI locations plus number and (A)ICD sizes,” Society of Petroleum Engineers doi: 10.2118/174309-MS, June 2015.
2. Eltaher, E.M.K., M.H. Sefat, K. Muradov and D. Davies, “Performance of autonomous inflow control completion in heavy oil reservoirs,” presented at the International Petroleum Technology Conference, doi:10.2523/IPTC-17977-MS, December 2014.
3. Halvorsen, M., and G. Elseth, “Increased oil production at Troll by autonomous inflow control with RCP valves,” SPE paper 159634, presented at the SPE Annual Technical Conference and Exhibition, Oct. 8-10, 2012, San Antonio, Texas.
4. Halvorsen, M., M. Madsen, Mo. M. Vikøren, I. Isma Mohd and A. Green, “Enhanced oil recovery on Troll field by implementing autonomous inflow control device,” Society of Petroleum Engineers, doi: 10.2118/180037-MS, April 2016.
5. Konopczynski, M., and M. M. Dowlatabad, “Improving the performance of EOR in unconventional oil reservoirs using advanced completion technology,” Society of Petroleum Engineers, doi: 10.2118/190260-MS, April 2018.
6. Moradi, M., M. Konopczynski, I. Mohd Ismail and I. Oguche, “Production optimisation of heavy oil wells using autonomous inflow control devices,” Society of Petroleum Engineers. doi: 10.2118/193718-MS, December 2018.
7. Dowlatabad, M. M., K. M. Muradov, D. Davies, “Novel workflow to optimise annular flow isolation in advanced wells, International Petroleum Technology Conference, doi: 10.2523/IPTC-17716-MS, December 2014.
8. Dowlatabad, M. M., F. Zarei and M. Akbari, “The improvement of production profile while managing reservoir uncertainties with inflow control devices completions,” Society of Petroleum Engineers, doi: 10.2118/173841-MS, April 2015.
9. Velez, B., W. M. Charry, A. Duarte, A. Beltran, L. Prent, J. Rubiano and N. Lopez, “A novel technique for wells that require gravel packing for sand control and inflow control devices for managing water encroachment: Case histories from Ocelote field in Colombia,” Society of Petroleum Engineers, doi: 10.2118/159743-MS, January 2012.
10. Voll, B. A., I. M. Ismail and I. Oguche, “Sustaining production by limiting water cut and gas breakthrough with autonomous inflow control technology,” Society of Petroleum Engineers. doi: 10.2118/171149-MS, October 2014.

About the Authors

Shuquan Xiong

CNOOC China Ltd._Shenzhen

Shuquan Xiong

Congda Wei

CNOOC China Ltd._Shenzhen

Congda Wei

Donghong Luo

CNOOC China Ltd._Shenzhen

Donghong Luo

Mojtaba Moradi

Tendeka

Mojtaba Moradi is a Subsurface manager at Tendeka in Aberdeen. He holds a PhD (2016) in petroleum engineering from Heriot-Watt University. He is a member of the European Association of Geoscientists and Engineers (EAGE), and SPE.