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North America's Leading Energy Event
September 21-23, 2021
BMO Centre at Stampede Park - Calgary, Canada

Co-Host

Polymer Flood Design in Heavy Oil Fields: Best Practices

Technical Stream | In partnership with Energy Now and Empowering Pumps & Equipment
Duration: 45 mins


In this webinar you will learn about good and bad practices in designing polymer flooding applications in heavy oil fields and about the most common operational problems. The material is based on many years of experience of laboratory testing and modeling of polymer flooding (Petro Nakutnyy and Gay Renouf, Saskatchewan Research Council) and design and troubleshooting of the field operations (Guy Bolton, Pi-Cubed Process Systems).

Some of the topics that will be discussed include:

• An overview of polymer flooding applications in Canada: a data-centric approach

• Why the conventional laboratory workflow may be ill-suited for polymer projects in medium to heavy oil fields and why aspect ratio of coreflood experiments is very important

• Why field performance of polymer flooding project often differs from the data predicted by laboratory and simulation studies

• What are the most common operational issues that affect polymer flooding projects and how to avoid them

Watch On-Demand 

Petro Nakutnyy
Manager, EOR Processes, Saskatchewan Research Council (SRC)

Petro Nakutnyy is the Manager for SRC’s Enhanced Oil Recovery (EOR) Processes Business Unit. His major technical responsibility is to conduct applied research and development of EOR processes and laboratory engineering design for the petroleum industry’s EOR projects. He has worked on a variety of enhanced oil recovery (EOR) projects in light, medium and heavy oil reservoirs, including chemical flooding, permeability modification and water shut-off, electrical heating and artificial intelligence. Petro’s team encompasses nearly three decades of experience and expertise in gas and chemical EOR solutions for conventional and unconventional oil reservoirs in the Western Canadian Sedimentary Basin. Petro holds a Master of Applied Science degree in petroleum engineering and is a registered professional engineer with the Association of Professional Engineers & Geoscientists of Saskatchewan.

Guy Bolton
Technical Director, Pi-Cubed Process Systems Ltd.

Guy Bolton is a technical consultant to the Oil and Gas industry. Amongst many other things he specialises in deployment, debugging and problem solving of Enhanced Oil Recovery chemical flood projects. He consults to asset owners, potential investors and the insurance industry.

Questions From the Session

I was involved with an EPC designing polymer flood facilities for several clients. For polymer distribution one client used coils for pressure / flow reduction. For other clients we used on/off valves and metered the injection volume to open/close the valves. Is this an acceptable method?

Guy Bolton: I was unable to fully answer this question during the presentation. I have some experience of using cycling valves for control of delivery of EOR fluids. They can work but in my experience are limited by reliability. To avoid undesirable effects the cycle needs to be rapid typically hourly. This tends to have a a negative impact on the valves. Wetted surfaces wear and drive mechanisms fail. My preference is the use of pressure reduction coils. Again, design can be carried out but must be carried out with care to avoid excessive polymer damage and irreversible reduction of solution viscosity. Ongoing testing needs to be done to check viscosity/quality of the injected polymer solution.

What type of stimulation do you recommend to solve injectivity issues in polymer injectors? Any specific chemical?

This is highly dependant upon the damage cause and to a large part to what degree damage has migrated into the formation. Damage is observed due to: (a) plugging related to polymer selection/quality/hydration (too high molecular weight, average or wide MW distribution; poor blending/hydration), this is usually prevalent at the sand face and can be rectified using aggressive oxidising agents. DO NOT push such reagents into the formation, simply apply at surface pressure, give it time to react and then swab the injection well; (b) Fines migration due to incorrect selection of EOR chemistry/injecting at too high a rate. There is not a lot that can be done to rectify such damage as observed effects tend to be deep in the reservoir; (c) scale formation, can be caused by incorrect water chemistry, blending of surface waters without adequate consideration of water compatibility etc. Assessment of potential injectivity issues due to polymer selection/quality/hydration can be done by reviewing pore size distribution of the formation and conducting high throughput injectivity tests in the lab. Determination of whether fines migration or scaling are likely causes may be assessed by review of surface water chemistry, geochemical modeling/laboratory tests, and detailed review of injection history. If scale effects are prevalent standard treatments can be applied, however the effects to flood front will likely be long term.

Can you comment on if geomechanics studies are completed on these projects, particularly on overlying caprock, and do you think suck studies could improved injection pressures by having a better understanding of caprock integrity? Thank you!

There has been several studies of caprock integrity for polymer flooding projects. While frack gradient is always considered as an upper limit for the injection pressure, to our knowledge, caprock integrity study is not currently always performed for polymer projects. Curiously, it is often discovered that injection pressure during polymer flooding is lower than expected, which likely implies that some fracture initiation/opening may be taking place near the injection wells. This can be both positive as it can reduce injection pressure and polymer shear near the injection wells, however, can lead to many issues if not understood/controlled (such as premature polymer breakthrough into producing wells, or even out of zone). Therefore, we believe that formation and/caprock integrity should be an important consideration for all flooding processes, including and especially polymer flooding.

In core floods the rate is typically held constant which actually provides a different dP for each core. This means the capillary numbers are different. You end up with higher recoveries from tighter rock. Have you looked at standardizing core floods to the cap number using dPs that might be seen in the field? Thank you.

Petro Nakutnyy: We generally design corefloods with flowrates equivalent to an appropriate field rate (such as 1 ft/day darcy velocity, but this is project dependant). Sometimes, when project relies on vertical wells, we pre-inject polymer at a high rate through a dedicated core to simulate near-well bore shear. This way, shear rate during coreflood experiments is realistic and close to the values fluids experience within the reservoirs. Shear rate is particularly important when testing polymers as they are non-Newtonian fluids. We also sometimes increase the flow rate at the end of waterflood to match the capillary number expected during the subsequent polymer flood. For tighter formations, where dP during the laboratory coreflood experiment may be unrealistically high, we often recommend reducing injection rate to achieve a more realistic pressure gradient. Particular parameters (rate, pressure) are always selected based on the objectives of the test and reservoir properties, and recommended values differ for studies focused on relative permeabilities, displacement performance, injectivity/inaccessible PV determination, etc. We also recommend using larger (ideally rectangular) 3D models where scale, heterogeneity, rates and pressure gradients can be set closer to the values expected in the field.

Thanks for the presentation. Can you please clarify your comment on why simulators are not there yet? Are the simulators missing some important effects, and if yes, which ones?

Petro Nakutnyy: A robust way to account for viscous fingering seen during polymer flooding in the simulation is still not available. There have been recent studies to show mathematical and empirical equations to explain and predict viscous fingering phenomena but more experimental work needs to be done to validate those theories. Coreflood experiments involving various aspect ratio, from 1D to large 3D sandpacks, could provide valuable insights into the initiation and propagation of viscous fingers and be used as input to improve simulation predictive capability.

What are the methods, measurements, analysis perform to identify that it is necessary to do first a conformance treatment? Are interwell tracers useful?

If field has been on waterflooding for a while, a lot of valuable information can be gleaned from the historic data (such as individual injector pressure and volume take-up rates, and response in the production wells). There are various methods to look at the interaction between injectors and producers, including capacitance model, streamline surveillance models, etc. We would also definitely recommend inter-well tracer studies. Fundamentally, you need to assess connectivity of each injector to various producers to determine where predominant breakthrough has occurred. Then you can use this information to decide whether any conformance (gel) treatments may be necessary before starting polymer flooding, and what is the optimal starting point in terms of polymer concentration/viscosity. We can help with reviewing the historical field production and planning further steps.

How can we tell if a finger is moving fast or the front is moving to fast. how do we monitor front speed before hitting a producer

Very difficult, in fact I have never seen an accurate assessment of flood front movement let alone early breakthrough predictions. However we would suggest looking at injection rate and pressure history, streamline surveillance models, analytical models or tracer studies. Overburden, underburden, heterogeneity, micro-fractures, nature of polymer, mobility ratio, etc. all play an important role in determining the movement of viscous fingers during polymer flooding. This may provide some indication when compared with early production numbers. Try to look at individual, then pool then field data.

What are the best practices for collecting and selecting enough core material for large aspect ratio core floods? Does a high degree of heterogeneity in the core stack cause inaccurate results?

Very difficult, in fact I have never seen an accurate assessment of flood front movement let alone early breakthrough predictions. However we would suggest looking at injection rate and pressure history, streamline surveillance models, analytical models or tracer studies. Overburden, underburden, heterogeneity, micro-fractures, nature of polymer, mobility ratio, etc. all play an important role in determining the movement of viscous fingers during polymer flooding. This may provide some indication when compared with early production numbers. Try to look at individual, then pool then field data.

How to properly estimate polymer solution degradation from the PIU to the sand face to have a target viscosity in the reservoir? Which degradation points are encountered on the way downhole (screens, valves...)?

All of the above! There are models that correlate flow velocity to elastic shear damage, we have built models based on these and on various other flow parameters. Do not push your polymer through screens or choked valves, depending on flow rates this can impart a huge amount of damage to the polymer. Preventing corrosion and oxygen ingress are also extremely important to minimize chemical degradation. For a well-managed injection program you can assume something like 10% loss at the sand face but this is a bit of guess. Polymer mechanical and chemical degradation will also depend on polymer molecular weight/structure of the polymer backbone, and can be estimated in lab tests. Continuous testing of polymer samples from the injection facility is also very important.

How about reduced injectivity? is that an issue? How can we prevent and/or recover from a formation damage due to polymer injection?

See answer to Q2. Laboratory injectivity tests can help to identify potential issues related to polymer quality/molecular weight. As an example, we assessed perceived injectivity loss of a single well in a medium sized field. In addition, it depends on what the profile of your reduced injectivity looks like and local geology. After reviewing various drill logs, production data, injection data for the local environment we drew the conclusion that the injector was isolated in a sand lens. The client had injected over an 18 month period slowly backfilling the lens. If injectivity is lower than expected at start-up you may be in a lower permeability zone than expected, review core samples. If however injection rates for a given flow or target pressure drop gradually it suggests there is some form of formation damage being imparted. Review your injection rates and implementation program, ensure that the critical fines migration velocity has not been exceeded at any time. Then look at water chemistry and confirm compatibility of injection fluids with formation water. Double and triple check the chemistry/water treatment and blending plant. Take lots of samples over a 24 hour period and analyse each. We have observed many plants that appear to cycle in blend concentration. cycle periods have varied between 20 mins and several hours. Once you have been through the assessment program you can then decide on an appropriate course of action. Note that injectivity appears to have been more of a problem in early polymer floods in western Canada than it is now. Reports of plugging from iron precipitation and scales were reported for the earliest oil sands polymer flood and for the heavy oil polymer flood at East Bodo. Reduced injectivity was reported at Viking-Kinsella Wainwright B, Wildmere, East Bodo, and Aberfeldy. The average permeabilities for these sites ranged from 300 to 3000 md.

Have you guys seen many successful conformance treatments?

We have observed data from lots of conformance treatments. Some appear to be successful, some appear to be successfully over a short time scale and some show no benefit. SRC can help with assessing the problem and identifying potential solutions, and connecting you with appropriate service companies. Our contact details are at the back of the presentation.

Hi Thanks for presentation. How can be reused the produced water with remanent polymer.

Guy Bolton: Ah, a subject close to my heart! Residual produced polymer if treated correctly can be reused within your blend water. There are a few tricks to making it work correctly. Adequate filtration is critical - refer to Aqua Pure Technologies. Blending must be carried out carefully and carry out adequate workup testing within your blending plant to ensure that you can make the transition smoothly.

How would you advise on production monitoring to avoid breakthrough based on Sw increase?

A comprehensive monitoring program should be implemented that includes but is not limited to injection well and production well water sampling, carry out chemical analysis on both and look for gradual increases in concentration at the producers. Look very carefully at produced oil water content. Also watch for subtle changes to produced oil, you are aiming to migrate otherwise stationary oil to your producers and this can look/smell different to conventionally produced oil. (My observation from a few fields and lots of conversations with operators). Control injection rates and pressures. As we mentioned in the presentation the design of start-up protocols is critical to limit the chances of early breakthrough.

At what point do wormholes prevent the flood from working ?

When an injector becomes hydraulically connected to a wormhole, control of injectivity pressure and direction of flood is lost. Development of a flood within a wormhole riddled formation must be carried out with extreme care.

For the end of the presentation, if not covered, I'm wondering if you can comment on caprock integrity related to polymer floods, how much is geomechanics considered for these projects, and do you think in-depth geomechanics studies (i.e. triaxial testing, tensile and shear strength testing of overlying caprock) might improve production, by determining caprock strength, thus potentially allowing injection at higher pressure? Thank you!

As a general guideline (and somewhat guided by local regulation) injectivity must be controlled at below caprock failure strength. To that end a clear understanding of caprock strength and integrity are critical. Failure of caprock will not lead to a happy ending! Also see our answer to Question #3.

Is there is two people talking at once?

Petro Nakutnyy, Saskatchewan Research Council (petro.naktunyy@src.sk.ca) and Guy Bolton, Pi-Cubed Process Systems Ltd. (Guy.Bolton@pi3process.com)

Can we have the access to the power point slides?

Yes. Please e-mail DMG, or directly Petro Nakutnyy (petro.nakutnyy@src.sk.ca) or Guy Bolton (Guy.Bolton@pi3process.com) and we will send you a PDF of the slide deck.

Thoughts on facility design. What are the main advantages to having 1 main facility vs multiple throughout the field?

Guy Bolton: I have lots and lots of thoughts about this. The biggest three are (1) cost (2) mobility/distribution, and (3) Reliability. There are strong arguments both for and against (1) and (2). (3) tends to be a function of (1) and (2). It depends enormously on the specific field, short term development plans and longer term development plans. My preference is for semi-mobile (or at least locatable) centralized plants but I have seen both work.

Since the adsorption rate and molecular weight of the tracers are so much different than the polymers could the tracers not be misleading?

Smart - and yes they can provide misleading information but from a high level view they can be used to determine water connectivity. Look at multiple tracer systems such that injection into several wells simultaneously allows for detection of proportion of each at a wide range of producers. As flood path velocity, I would not recommend the use of tracers. Lab studies of inaccessible pore volume/dynamic adsorption can be used to better relate tracer and polymer formation travel data.

Can a polymer flood be economically viable at current oil prices? how do you see the future for polymer flood projects?

Depends heavily on your local cost environment, project size, etc. but yes we do see a long term future for polymer projects.

What is the best treatment of fluids produced when there are emulsion problems in surface facilities due to polymers? Thanks.

We have observed excellent separation using ceramic membrane filtration plants (again see Aqua Pure Technologies). Steer clear of DAF or injected gas floatation systems they seem to work well initially but need continually retuning. Heat is your friend on many fronts. Polymer viscosity falls off with temperature and then breaks down fully at 90 Celsius. SRC can review the details of a particular problem and suggest solutions, as well as provide an independant comparison of emulsion breakers from various suppliers. Finally, chat with your local production chemistry representatives, standard emulsion breaker surfactants can be applied.