foam lifting manual

NEDERLANDSE AARDOLIE MAATSCHAPPIJ B.V.

Foam Lifting Manual: Current Best Practices from the Land Asset

Report: EP200609223511

Author: Chad Wittfeld Production Technology

Contributing Foam Team: Gert de Vries Production Chemistry Dick Klompsma Well ServicesGerrit de Jong Operations EngineeringRob Smeenk Production TechnologyEfstathios Kitsios Production TechnologyEwout Biezen Production Technology

Nederlandse Aardolie Maatschappij

1 ACKNOWLEDGEMENTS...............................................................................................................32 INTRODUCTION............................................................................................................................ 3

2.1 THE ROLE OF FOAM...................................................................................................................32.2 NAM BACKGROUND...................................................................................................................32.3 THE CHALLENGES...................................................................................................................... 32.4 PURPOSE OF THIS MANUAL........................................................................................................3

3 SUMMARY..................................................................................................................................... 33.1 FOAM PRINCIPLES.....................................................................................................................33.2 BATCH FOAM............................................................................................................................. 33.3 CONTINUOUS FOAM....................................................................................................................33.4 CANDIDATE SELECTION..............................................................................................................33.5 CHEMICAL CONSIDERATIONS......................................................................................................33.6 MATERIALS CONSIDERATIONS.....................................................................................................33.7 CONTINUOUS FOAM INSTALLATION PROCEDURE..........................................................................33.8 POST-INSTALLATION MAINTENANCE............................................................................................33.9 COST OVERVIEW.......................................................................................................................3

4 FOAM PRINCIPLES....................................................................................................................... 34.1 REDUCTION IN CRITICAL RATE.....................................................................................................34.2 DELIVERY METHODS...................................................................................................................3

5 BATCH FOAM................................................................................................................................ 35.1 TYPICAL PROGRAM..................................................................................................................... 35.2 FOAM VOLUMES.........................................................................................................................35.3 CHASER.................................................................................................................................... 35.4 DEFOAMER................................................................................................................................ 35.5 EVALUATION OF TREATMENTS.....................................................................................................35.6 FALL RATE................................................................................................................................. 35.7 RESULTS TO DATE..................................................................................................................... 35.8 SUCCESSFUL WELL EXAMPLES....................................................................................................35.9 UNSUCCESSFUL WELL EXAMPLE..................................................................................................3

6 CONTINUOUS FOAM....................................................................................................................36.1 SUBSURFACE EQUIPMENT..........................................................................................................3

6.1.1 Modified SCSSV...............................................................................................................36.1.2 LK-2 injection valve...........................................................................................................36.1.3 Capillary string..................................................................................................................36.1.4 Double back pressure valve.............................................................................................3

6.2 SURFACE EQUIPMENT................................................................................................................36.2.1 IBC containers..................................................................................................................36.2.2 Pump Skid........................................................................................................................36.2.3 Filter.................................................................................................................................. 36.2.4 Pump................................................................................................................................ 36.2.5 3-way valve....................................................................................................................... 36.2.6 Meters............................................................................................................................... 36.2.7 Pressure Safety Valves....................................................................................................36.2.8 Skid operation................................................................................................................... 36.2.9 Defoamer Skid..................................................................................................................3

6.3 RESULTS TO DATE..................................................................................................................... 36.4 WELL EXAMPLES.......................................................................................................................36.5 ALTERNATIVE DEPLOYMENT SYSTEM..........................................................................................3

7 CANDIDATE SELECTION.............................................................................................................37.1 BATCH FOAM............................................................................................................................. 3

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7.1.1 Water to condensate ratio.................................................................................................37.1.2 Presence of downhole chemicals.....................................................................................37.1.3 Type of condensate..........................................................................................................37.1.4 Lab testing with sampled fluids.........................................................................................37.1.5 Total Dissolved Solids......................................................................................................37.1.6 Suspended solids.............................................................................................................3

7.2 CONTINUOUS FOAM....................................................................................................................37.2.1 Success on batch foam....................................................................................................37.2.2 Critical rate will be lowered enough..................................................................................37.2.3 Inflow performance optimized?.........................................................................................37.2.4 Wellbore access...............................................................................................................37.2.5 Temporary test well candidate?........................................................................................3

7.3 CLOSING REMARKS.................................................................................................................... 3

8 CHEMICAL CONSIDERATIONS....................................................................................................38.1 FOAMER REQUIREMENTS...........................................................................................................3

8.1.1 Foaming Ability.................................................................................................................38.1.2 No solids........................................................................................................................... 38.1.3 Winterized.........................................................................................................................38.1.4 Thermal stability................................................................................................................38.1.5 Non-corrosive...................................................................................................................38.1.6 Elastomer compatibility.....................................................................................................38.1.7 Emulsions.........................................................................................................................38.1.8 Water in condensate emulsions........................................................................................38.1.9 Condensate in water emulsions........................................................................................3

8.2 COMPATIBILITIES OF FOAMERS WITH OTHER FLUIDS.....................................................................38.3 DEFOAMERS.............................................................................................................................. 38.4 FOAMER PORTFOLIO AND PREFERRED PRODUCTS......................................................................3

8.4.1 Preferred batch foamer (satellite locations)......................................................................38.4.2 Preferred batch foamer (locations with facilities)..............................................................38.4.3 Preferred continuous foamer............................................................................................3

8.5 FURTHER DEVELOPMENTS..........................................................................................................3

9 MATERIALS CONSIDERATIONS..................................................................................................39.1 WELL FLUID EXPOSURE.............................................................................................................39.2 IBC TANKS................................................................................................................................ 39.3 OTHER SURFACE EQUIPMENT.....................................................................................................39.4 FILTER FOULING......................................................................................................................... 39.5 ELASTOMER COMPATIBILITY.......................................................................................................3

10 INSTALLATION..........................................................................................................................310.1 PRE-INSTALLATION (HUD CHECK)...............................................................................................310.2 PROCEDURE.............................................................................................................................. 310.3 SETTING DEPTH......................................................................................................................... 310.4 FLUID FLUSHING (MAC-GEL)........................................................................................................310.5 START-UP.................................................................................................................................. 310.6 INJECTION RATE.........................................................................................................................3

11 POST-INSTALLATION MAINTENANCE....................................................................................311.1 LEAKS....................................................................................................................................... 311.2 FILTER PLUGGING...................................................................................................................... 311.3 INJECTION RATE MONITORING/SAMPLING.....................................................................................311.4 CHANGING FOAM....................................................................................................................... 311.5 “ABANDONING” A FOAM WELL......................................................................................................3

12 COST OVERVIEW......................................................................................................................312.1 BATCH FOAM COST BREAKDOWN...............................................................................................312.2 CONTINUOUS FOAM COST BREAKDOWN......................................................................................3

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12.3 SURFACE MODIFICATIONS...........................................................................................................312.4 CAPILLARY STRING..................................................................................................................... 312.5 MODIFIED SCSSV.....................................................................................................................312.6 SUBSURFACE INSTALLATION.......................................................................................................312.7 CHEMICALS............................................................................................................................... 312.8 MAINTENANCE/POST-INSTALLATION SERVICES.............................................................................312.9 COSTS TO DATE OF LAND INSTALLATIONS...................................................................................3

ACKNOWLEDGEMENTS

The work presented in this document and the successes achieved and the knowledge gained to date are the result of a multi-disciplinary effort that has persisted for several years. Although this document was written and had contributions from members who now form the active Foam Team, many others have been involved to date in various roles. Special acknowledgements are given to:

Production Technology and Production Chemistry staff who initiated the first trials and the development of the first generation of continuous foam hardware

Operations staff in the various clusters who have worked with the batch foam wells and the continuous foam installations

Well Services staff who have helped in planning, logistics and execution of batch foam jobs as well as in installation and troubleshooting of continuous foam installations

Production Chemistry laboratory staff who have supported various lab tests

This support has been critical for success of the project to date, and will remain a critical requirement as deployment of foam moves forward.

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1 Introduction

1.1 The Role of FoamLiquid loading currently affects over 50 wells in the Land Asset, deferring an estimated 1MMm3/d, and the reserves in the Land Asset that are held by liquid loaded wells is currently estimated at approximately 2 mrd m3. More than 80 wells accounting for approximately 7.5 MMm3/d of capacity in the OneGas offshore asset suffer from liquid loading as well.

Application of surfactants, or “foam”, for mitigating liquid loading in gas wells is a mature technique that has been applied for decades in the onshore US as well as in other parts of the world. Foam was identified as a potential solution to liquid loading in NAM wells and was first tried in the Land Asset in October of 2003. Results were very positive and led to plans for further implementation.

An evaluation of all possible liquid loading solutions and the applicability to wells in the Land Asset was carried out in April 2005, and the results of the study confirmed that foam was one of the technologies most applicable to mitigating liquid loading in the Land Asset1. It is a strategically important technology for maximizing tail-end production from existing wells, and there is a strong drive to realize wide implementation and to build up internal expertise in all aspects of foam lifting.

1.2 NAM BackgroundFoam began in NAM with a trial of batch foam in ~30 wells and temporary, manned tests of continuous foam via a capillary string in 2 wells in the land asset. Following the encouraging results noticed in these trials, it was decided to expand the application to more wells and increase the incremental gas production from the technique.

Following the initial trials, batch foam has been deployed on a large-scale basis in the Land Asset, and 7 installations of continuous foam injection have taken place. Four of the installations have been clearly successful, while the other three did not deliver the desired results for various reasons. Various foamers have been tried, modifications have been made to equipment, and multiple well interventions have occurred for maintenance of the different systems. Another 6 installations are planned for the end of 2006 and beginning of 2007.

1.3 The ChallengesDue to the requirement to have sub-surface safety valves in all wells in the Netherlands, it was required to use new equipment to deliver the foam downhole for continuous foam applications. The equipment used was based on in-house designs and was outsourced to a vendor. The technique is a world-first method of deploying chemicals downhole through a capillary string while still maintaining full functionality of the SCSSV. Although the technique of foam lifting without SCSSV’s is quite mature in the onshore US, the introduction of new chemicals into NAM operations combined with the deployment of a world first delivery technique has resulted in much learning to date. This learning and the overall results of the project have been achieved with dedicated focus from a multi-disciplinary team.

1.4 Purpose of this ManualThis document serves as an overview of the current best practices of foam lifting within NAM. Experiences gained over the years since the project was kicked off have been summarized. This document should be used to give an overview of the critical issues to be taken into account and how to maximize the probability of success for anyone who is interested in applying foam lifting in an asset. In addition to the manual, the foam team should be engaged at an early point to advise on the specific aspects of a job.

1 Wittfeld, Chad, et al, Making the Most of Our Tail-End Production: Mitigating Liquid Loading, Apr 2005

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This is a live document that will require updates on a regular basis.

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2 Summary

2.1 Foam PrinciplesThe application of surfactants, or “foam” to liquid loaded wells enables the wells to flow below the normal critical rate in given conditions by preventing liquid slip between the gas and liquids to be unloaded. While industry publications indicate various numbers, NAM experience shows a reduction in critical rate of at least 33%, and possibly as much as 50%. Foam is delivered primarily in two manners- batch and continuous.

2.2 Batch foam Batch foam is carried out by pumping a fixed volume of foam down the tubing periodically. The well is closed in, a certain volume is pumped, and then the well is opened later. A typical foam job is 50 liters of foamer pumped down the tubing, and a chaser of 200 liters of 1.05 KCl brine is pumped after the foam job to aid the foam in falling down the tubing. Data suggests that the fall rate of a batch foam job is approximately 100 meters per hour, and a well should be shut-in long enough to allow the batch to travel down to the desired depth prior to opening the well for production.

It is recommended to do at least 5 batch foam jobs on a well before trying to draw a conclusion on whether it has been successful or not. Ideally, the well should be put on a cycle with the batch foam for several weeks, and if in doubt of the results, the well should be put on the same shut-in/open schedule without foam for comparison. Wells with a regular intermittent production schedule make this testing easier to carry out.

Close to 50% of the wells that have been tried with batch foam on a consistent basis have shown successful results. Approximately 30% are still inconclusive, while 20% clearly show no improvement.

2.3 Continuous foamIn a continuous foam application a capillary string is run from surface down to near the perforations, and foamer is injected continuously downhole while the well is produced. Typical installations of foam injection via a capillary string in onshore operations outside of the Netherlands are carried out by simply running a capillary string through the X-mas tree, inside the tubing down to the desired injection interval. However, in NAM, SCSSV’s are required for use in all wells. Therefore, a new system was developed to allow injection of foam downhole via a capillary string while still maintaining full functionality of the SCSSV system.

In this system, foam is used as the control line fluid to hold the flapper open as well as to be injected downhole. The foam is pumped through a 3-way valve on surface and then into the control line going down to the landing nipple. A modified SCSSV is set in the landing nipple that allows the foam to act on the flapper valve or to pressure up against an LK-2 chemical injection valve that controls injection into the capillary string. At a certain pressure the flapper opens, then at a higher pressure the LK-2 injection valve is opened and foam flows into the capillary string and eventually into the well.

Due to the fact that foam is used in place of the standard hydraulic oil, it is necessary to decouple the well from the previously used hydraulic well control unit and install a new pump and other components that are tied into the ESD system on location. The main components that are installed on surface for foam injection are an IBC container and a pump skid that includes metering and a 3-way valve.

2.4 Candidate SelectionDepending on the environment where foam is desired to be applied, it may be easiest just to pump it and see what happens. Should that not be possible, the following criteria are found to maximize the probability of success:

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High water to condensate ratio No downhole chemical injection that may act as a defoamer (i.e. corrosion inhibitors) Successful foam testing in the laboratory with produced fluids from the well No heavy condensate fractions Critical rate will be lowered enough (well will be able to flow with a 33% reduction in critical

rate) Inflow performance is already optimized Wellbore access to setting depth for continuous foam applications

For continuous foam applications, batch foam should always be tried first to see if any reaction is observed. A good reaction on batch foam will strengthen a case for continuous foam, but lack of success does not necessarily mean that a well will not respond to continuous foam. At least one example of this exists in the Land Asset where a well showed no reaction to batch foam but later was successful with a continuous foam application. Another approach would be to carry out a temporary test with a capillary string in a well to see how it would respond to a permanent continuous foam system. However, there is a high chance that such a test may be inconclusive depending on the well characteristics or lack of sufficient test time.

2.5 Chemical ConsiderationsThe foaming chemicals available- both foamers and defoamers- have certain chemical qualities which must be taken into account, some of which were not expected when foam was introduced into NAM. Much of the focus in the project to date has been on the corrosivity of foamers due to dissolved oxygen that is present, and thermal stability has also been identified as a very important issue.

Experience with various chemicals has led to creation of a standard criteria checklist2 that must be passed before any new foamer can be used. Some of the main criteria are the following:

Good foaming ability Non-corrosive (for continuous foam applications) Thermally stable (for given well conditions) Winterized to –20 C Compatible to elastomers (for continuous foam applications) Low emulsion tendency

Special attention must be paid to compatibility of foamers with either other foamers or fluids that they may come in contact with during operation. A chart of compatibilities with foamers and other common fluids is presented in the main document.

Defoamer is recommended to be used on locations where process facilities exist. The required defoamer depends on the type of foam used, as more concentrated foamers require stronger defoamers.

A breakdown of all foamers tried to date and their advantages and disadvantages is presented in the main document. Based on all considerations, the preferred product for batch foam applications on locations with facilities is FoamerA. For batch foam on locations without facilities, FoamerI is the preferred product. For continuous foam applications, FoamerI is the currently preferred foamer.

2.6 Materials ConsiderationsAll metal materials on surface as well as subsurface must be stainless steel with at least 13% chrome content to avoid potential corrosion due to the dissolved oxygen in foamers. Subsurface elastomers used are of Kalrez quality, and the surface equipment contains a mix of Viton and NBR elastomers. These have proven to be compatible with the foams that are used.

2 contact Gert de Vries for details

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2.7 Continuous Foam Installation ProcedureInstallation of a continuous foam system is typically carried out in 2-3 days and requires NAM wireline and a BJ capillary string truck. Special consideration must be given to flushing of the control line with an appropriate spacer to avoid foam coming in contact with hydraulic oil. A standard pump skid is available for the surface modifications, but site-specific tie-ins and engineering work will always be required in order to interface with the local ESD system.

2.8 Post-Installation MaintenanceFollowing the initial installation, the system will still require periodic maintenance. Leaks may occur either in the surface or sub-surface equipment that will require intervention and replacement of components. Surface filters may require periodic change-out as well should any fouling occur.

The injection rate should be monitored and if possible, samples should be taken and analyzed for foam breakdown time to determine how much scope exists for reducing the foam injection rate as low as possible.

2.9 Cost OverviewA typical installation cost for the subsurface and surface modifications for an onshore application is ~ € xxx. The subsurface costs can vary depending on the materials and sizes of downhole equipment required for different wells. The cost for the surface modifications can vary depending on whether or not a defoamer skid is also required.

After installation the main costs will be the chemical usage and whatever maintenance may be required on the system. The foam chemicals cost ~€ x/ltr. Depending on the required injection rate these costs range from € xxx up to € xxx per year. A typical leak fixing operation for a subsurface leak will cost approximately € xxx. The total cost to date of the installations on land have been calculated with actual cost figures from SAP. The seven installations have an average cost of € xxx to date.

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3 Foam Principles

3.1 Reduction in critical rateThe application of surfactants, or “foam” to liquid loaded wells enables the wells to flow below the normal critical rate in given conditions by preventing liquid slip between the gas and liquids to be unloaded. This reduction in slip is achieved by lowering the surface tension between the water and gas as well as lowering the density of the water phase to be lifted out of the well. Examination of the Turner equation for determining critical rate of gas flow in a well can demonstrate the theoretical effect of foam on the critical rate:

Velocity- ft/sDensity- lbm/ft3Surface tension- dynes/cm

Literature suggests that the surface tension can be reduced from a value of 60 to 30 dynes/cm, and the density of the liquid droplets (ρl) will be reduced to 20% of the previous value. From this equation and these reductions in value it can be calculated that the critical rate with foam generated downhole should be reduced by ~30% as compared to the previous value.3

Field experience from NAM installations supports this theoretical reduction in critical rate. Data from WAV-18 is shown in the WePS curves below:

3 Campbell, et al, Corrosion Inhibition/Foamer Combination Treatment to Enhance Gas Production, SPE 67325

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The P-Q curve calculated by WePS shows that the well should be unstable at a THP of ~12 bar and 30,000 m3/d of flow through the 3 ½” tubing. The test points plotted on the graph are taken from periods of operation with continuous foam injection. Prior to installation of the foam injection the well would flow only ~12,000 m3/d at various THP’s. One point is demonstrating this flow in the plot. The other test points after continuous foam injection was begun demonstrate that the well can flow at THP’s and rates where it was not previously possible to flow. By preventing liquid slip down to a certain flow rate, the well behaves along its P-Q curve for unloaded flow down to a certain point at which the foam cannot reduce liquid slip anymore. Similar to the theoretical reductions in critical rate, the data from this well shows a reduction in the critical rate from 30,000 m3/d to 20,000 m3/d, which is a reduction of ~33%. Data from MKZ-3 is shown in the figure below which shows stable flowing points suggesting a reduction in critical rate from 180,000 to 100,000, which is a reduction of ~45%.

It should be stated that the flowing data from the point that was ~45% of the previous critical rate was not a very long period, and therefore it is conservatively suggested that a 33% reduction should be used based on NAM experience.

Some vendors claim that reductions in critical rate of close to 80% can be reached. However, no data has been seen to date to support these claims and it is not recommended to make decisions based on those claims at this time.

3.2 Delivery methodsFoam is delivered primarily in two manners- batch and continuous.

Batch foam: well is shut in and a certain volume of foam and chaser is pumped down the tubing, then the well is opened up the next day.

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Continuous foam: a capillary string is run from surface down to near the perforations, and foam is injected continuously downhole while the well is produced.

These two methods are described in more detail in the following sections.

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4 Batch FoamBatch foam is carried out by pumping a fixed volume of foam down the tubing periodically. The well is closed in, a certain volume is pumped, and then the well is opened later. For the land operations, well services has a dedicated foam truck which can hold several types of foamer and the required chaser liquid. Multiple wells can be treated in the same day if located nearby each other.

4.1 Typical programA typical program for a batch foam job is as follows:

1. Close in well2. Close kero-test valve3. Bleed off pressure from kero-test and remove bleeder plug 4. Connect hose from foam truck5. Open kero-test valve6. Pump 50 liters of foam7. Pump 200 liters of brine chaser8. Close kero-test valve9. Remove hose10. Reinstall bleeder plug11. Open kero-test valve12. Open well next day and inject defoamer in flowline if required

4.2 Foam volumesFor batch purposes, a general rule of thumb is to try and pump a foam volume that will result in 10,000 ppm of foamer in the volume of water to be unloaded. However, it is often not known how much water is present downhole when a job is to be pumped.

Without knowledge on the amount of liquids to be foamed, a typical foam job is 50 liters of foamer pumped down the tubing. After a reaction is seen consistently, it is usually desired to reduce the foam volume down to 25 to see if the same results are achieved. Overdose of foam can lead to emulsions and also is wasteful of the chemical. Larger foam volumes of 100 or 150 liters can be tried if it is suspected that a large amount of liquids is downhole.

4.3 ChaserA chaser of 200 liters of 1.05 KCl brine is pumped after the foam job. The purpose of this is to mix with the foam and help it to get down the tubing. In the beginning of the project, 1.15 NaCl brine was used. The idea was that this heavy brine would help the foam travel through the condensate and water that was present in the well, thus dispersing the foamer in the fluids to be lifted. This was discontinued due to fear of creating salt bridges in the tubing. A salt bridge was found in one well, and after switching to the KCl no other bridges have been observed. There has been no noticeable change in performance of the batch foam injection with the KCl as compared to the NaCl.

For a certain period, the FoamerI foamer was pumped with no chaser at the recommendation of the vendor. However, it was later noticed in the lab that the solvent package of this foamer could evaporate at higher temperatures, leaving behind the very viscous pure foaming agent. Therefore a chaser has been used again with this foamer to help ensure that it gets down the tubing. Results of whether or not this makes a difference in the success rate with this chemical are still to be evaluated.

4.4 DefoamerThe approach taken to date has been that all locations where processing facilities exist (compressors, glycol dehydration, etc.) require the use of defoamer, and all satellite locations do not require

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defoamer as it is assumed that the foam breaks down while being transported in the flowline. No problems have been observed due to foam from a satellite location to date.

The recommended procedure for defoamer injection for a batch foam job is to pump 10 ltr/hr of defoamer for five hours when the well is opened up the day after the batch foam job. The defoam injection should be started just prior to opening the well.

4.5 Evaluation of treatmentsUnfortunately, batch foam and the evaluation of the results is not an exact science. Due to the delivery method of the foam, the transient nature of the wells and other factors that vary every time a job is carried out, it is recommended to do at least 5 batch foam jobs on a well before trying to draw a conclusion. Ideally the well should be put on a cycle with the batch foam for several weeks, and if in doubt of the results, the well should be put on the same shut-in/open schedule without foam for comparison. Wells with a regular intermittent production schedule make this testing easier to carry out.

An example of a well on a regular intermittent cycle is shown below:

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In the figure, the red lines indicate the dates where a batch foam job was pumped. Foam was stopped for a period of 6-7 weeks to evaluate how the well responded to a shut-in cycle alone. In this example, it can be seen that the production is more stable when the weekly foam jobs are carried out as compared to the period when the foam was not injected. The foam was therefore continued on this well after seeing this comparison.

4.6 Fall rate Wells are typically left shut-in overnight to allow the foam to travel down the tubing to the liner/perfs area. Acoustic liquid level tracking with the Echometer suggests that the fall rate is approximately 100 meters per hour. This means that for a 3000 meter deep well, a shut-in time of more than 24 hours is required. This is based on measurements from the first couple of hours in the well; a batch foam job has not been tracked through the whole tubing yet. However, it is recommended to use 100 meters per hour as a conservative fall rate until further data is available.

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WYK-4 Foam tracking

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4.7 Results to dateApproximately 60 wells have been tried on batch foam over the past few years. The wells are broken down into the following categories:

Successful- these wells show clear improvement with batch foam as compared to similar periods without batch foam

Unsuccessful- these wells clearly show no improvement with foam as compared to without foam

Inconclusive- it is difficult to draw a conclusion from these wells due to a lack of consistent treatments, periods with long pressure build-up or other factors.

Not applicable- foam has been tried on some wells that were either stably flowing already, or were suffering from significant inflow impairment such as a HUD buildup or were of poor reservoir quality and were interpreted to be liquid loading.

If the “not applicable” wells are removed, then the focus is put on the wells that are known to be suffering from liquid loading as the primary reason for low production. The breakdown of the results are shown in the figure below:

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Batch foam well results (filtered)

Successful

Not successful

Inconclusive

Close to 50% of the wells that have been tried with batch foam on a consistent basis have shown successful results. Approximately 30% are still inconclusive, while 20% clearly show no improvement.

4.8 Successful well examplesSuccessful wells can have varying reactions. Some examples are shown in the following figures. Below is an example taken from WAV-8:

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In this case batch foam is carried out on the well on a regular schedule to maintain unloaded production and prevent liquid loading from occurring. It can be seen in the circled periods that if one of the regularly planned foam jobs is skipped, the well has a high chance of loading up.

WYK-11 is shown in the figure below:

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In this example, the well flows very stable the majority of the time, but suffered from liquid loading at one point due to a slightly higher pressure in the flowline. The well was shut-in overnight a few times to try and produce intermittently, but did not work. After the first batch foam job the well came directly back to the unloaded production levels and has stayed there since that time.

Finally, WAV-11 is shown in the following figure:

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In this example, the well would show an increase in production directly after most batch foam jobs, but it would decline quickly thereafter back down to liquid loaded levels. It was therefore moved to a weekly batch foam frequency, and the average gas production increased due to the ability to keep the well unloaded with more frequent batch foam. This example shows the importance of optimizing the frequency of batch foam after a successful well has been identified. This well has been converted to continuous foam after the good success observed on batch foam.

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4.9 Unsuccessful well exampleAn example of an unsuccessful well (COV-53) is shown in the figure below:

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This well clearly shows no increase in production when comparing periods before and after the foam is pumped. Factors that affect the success of foam jobs are discussed in the candidate selection section.

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5 Continuous FoamTypical installations of foam injection via a capillary string in onshore operations outside of the Netherlands are carried out by simply running a capillary string through the X-mas tree, inside the tubing down to the desired injection interval. Sub-surface safety valves (SCSSSV’s) are currently not required in onshore wells where this technique is applied in other areas. However, in NAM, SCSSV’s are required for use in all wells. Therefore, a new system was developed to allow injection of foam downhole via a capillary string while still maintaining full functionality of the SCSSV system. This system requires modifications to typical SCSSV components on surface as well as subsurface. An overview of a typical system is shown in the figure below:

No Component1 IBC containers2 Filter3 Pump4 Check valve5 Coriolis meter6 3-way valve7 Control line in annulus8 2.75" LNSV9 2.75" Halliburton CISV

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In this system, foam is used as the control line fluid to hold the flapper open as well as to be injected downhole. The foam is pumped through a 3-way valve on surface and then into the control line going down to the landing nipple. A modified SCSSV is set in the landing nipple that allows the foam to act on the flapper valve or to pressure up against an LK-2 chemical injection valve that controls injection into the capillary string. At a certain pressure the flapper opens, then at a higher pressure the LK-2 injection valve is opened and foam flows through the capillary string and eventually into the well after passing the back-pressure valve.

5.1 Subsurface EquipmentThe key components of the subsurface system are the following:

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5.1.1 Modified SCSSVThe ability to deliver the chemical downhole and still operate the flapper valve is achieved by using a modified SCSSV. Two previous designs exist, and improvements are being made to incorporate learnings and improvements into new designs. An example of the current design for 3 ½” tubing wells is shown with the flapper open and also with a closed flapper in the figures below:

The foam (pink line) travels down the control line and into the seal bore of the landing nipple, and then is taken into the valve via a port. Once in the valve, the foam has two paths it can travel which are controlled by pressure. One path is that it can pressure up on the flapper as in a normal SCSSV to open the flapper, the other path is that it can travel down the side of the valve and into the capillary string for injection downhole after passing through the LK-2 injection valve. This design is available for the 2.75” nipples as well as the 3.813” nipples. A deep-set version exists for the 2.75”, and the valves are available in different materials.

For wells with landing nipples larger than 3.813”, an insert sleeve is required in addition to the modified SCSSV. The insert sleeve is installed first in the LNSV with wireline, and then the capillary string and modified valve are landed in a nipple profile in the insert sleeve. Foam flows first through the insert sleeve, then into the pathways described above. The insert sleeve is required due to limitations on the BOP stacks that are available. The current used BOP stack functions to allow diameters of up to 4 1/16” pass through, while still being able to close around the capillary string when required. For the larger sizes of equipment, something closer to a drilling BOP would be required to allow passage of equipment of that size, and that is not considered practical to use for these operations.

The initial installations in wells with larger tubing were equipped with a somewhat different concept. It is described in Appendix 1. This design was designed by NAM and machined locally, but has now been replaced by the new Halliburton designs.

5.1.2 LK-2 injection valveThe injection downhole is regulated by a BKLK-2 chemical injection valve that sits directly under the flapper valve. Typical settings for operation of the valve would be a flapper opening pressure of 70 bar, while the LK-2 valve is set only to open and allow injection above a pressure of 150 bar. This allows also the possibility of holding the flapper valve open without injecting any foam downhole, if desired. This valve is responsible for pressure regulation in the system. Any failure of this valve or any of the seals upstream to hold pressure or operate in the desired setting will result in an inability to hold the flapper open or to inject foam downhole.

The first installation of the 3 ½” valve system did not have the LK-2 valve installed under the flapper. Pressure maintenance in the system was dependent on the double back pressure valve that was set at the end of the capillary string. Due most likely to the long length of the capillary string between the flapper and the valve, this setup resulted in very irregular pressure behavior where the injection

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pressure would sometimes come below the flapper closing pressure and the flapper would close. In order to fix this, the LK-2 was incorporated into the design. A picture from WAV-18 shows the pressure behavior before and after the installation of the LK-2 valve:

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It is clear from the graph that the injection pressure (red line) is much more stable after the installation of the LK-2 under the flapper, and it is therefore considered a necessary part of the installation.

5.1.3 Capillary stringThe capillary string used is ¼” OD with a wall thickness of 0.035”. The material is Incoloy 625. Current experience in NAM indicates that limitations of this capillary string are depths of around 4000 meters, after which it may break under its own weight when being pulled out of a well. Vendor modeling packages and experience may provide further insight into what is possible in different wells.

5.1.4 Double back pressure valveThis valve serves as the two barriers while running the assembly in the well. The valve has a certain opening pressure and is typically set to hold the hydrostatic head in the capillary string, but not to regulate the injection pressure of the system. That function remains with the LK-2 valve positioned under the flapper.

It is also possible to run a downhole gauge as part of the bottomhole assembly. Should the string be retrieved for any reason, the data can be downloaded.

5.2 Surface EquipmentDue to the fact that foam is used in place of the standard hydraulic oil to keep the flapper open, it is necessary to decouple the well from the previously used hydraulic well control unit and install a new pump and other components which are tied into the ESD system on location, otherwise the hydraulic oil from the other wells would mix with the foam in case of a bleed down of pressure for a shutdown. Because the system is used to operate the SCSSV, it must have tie into the existing ESD system and provide full functionality for emergency situations. An example of the PEFS from a surface skid is given in Appendix 3. The components that are installed on surface for foam injection are the following:

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5.2.1 IBC containersThe foam is typically stored on surface in IBC containers situated in a “mother/daughter” configuration. The mother container is the lower IBC and it is in a fixed position, while the daughter container sits above the mother and can be replaced when a refill on foam is required without requiring a shutdown of the system. The containers are made of stainless steel and can hold ~1 m3 each. In order to check the quantity of the foam in the IBC, mother container is preferably equipped with a sight glass for visual inspection of the level by the operator. Most IBC’s are delivered with a pressure vacuum valve. As the valve is not suitable for pumping out, it must be replaced by a vent pipe.

5.2.2 Pump SkidA standard pump skid has been designed for foam injection and can be reproduced for future installations. The skid consists of the following components:

5.2.3 FilterThe first component in the pump skid is a filter upstream of the pump intake. The purpose of the filter is to filter out any particles that may be present in the foamer that would lead to plugging or erosion of downstream components. The mesh size of the filter has been specified to be 20 micron at the moment. It is in place to protect the downhole equipment as well as the 3-way valve downstream of the pump.

The initial installations only were equipped with coarse filters of 1 mm, and the WAV-18 downhole equipment became plugged at the downhole double-back pressure valve. A full change-out of the subsurface equipment was required to fix this. Standard industry recommendations are 100 micron mesh filters to protect downhole capillary string installations. The mesh size was reduced to 20 microns to protect the 3-way valves downstream of the pump. The reason is described in the 3-way valve section.

The filters had seen some problems with fouling in the past due to what was most likely corrosion products coming from upstream of the filters, but this has not been seen after most installations were switched to the non-corrosive FoamerI. This is discussed more in the chemical considerations section.

5.2.4 PumpThe pumps used on the standard skid are Milton Roy plunger type injection pumps, with a maximum injection pressure of 400 bar. The first series of skids have been equipped with standard pumps with a maximum capacity of ~140 ltr/d and a turndown ratio of ~10:1 as observed in practice. The second series of skids currently being built will be equipped with pumps with a capacity max ~50 l/d, as it has been seen that the high injection rates are not required in most wells.

These pumps were selected in part due to the fact that they can deliver a constant injection rate despite fluctuating downstream pressures. In initial installations pumps were used which had injection rates very dependent on the discharge pressure, and this is not desirable to have in a system where a constant chemical dosage rate is desired.

5.2.5 3-way valveThe 3-way valve is located downstream of the pump and is an essential part of the ESD functionality. During normal operation the 3-way valve allows flow from the pump to the control line in the well. However, when the SCSSV is required to close, the valve switches position and the line from the well is open to a bleed down either into a open pit or to a separator, and the line from the pump to the well is blocked off. This allows the control line to depressurize and the SCSSV to close.

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Problems were experienced with the existing 3-way valves in the HWCU’s that were used for the first installations. These problems were due to problems with the solenoid and material problems. Therefore it was desired to make the 3-way valves part of the new skid design in order to avoid problems. An electric 3-way valve was selected due to the possibility of a lack of instrument air on some locations and also to eliminate the need to run air lines to the skid.

Upon initial installation of these valves in the new skid applications, almost all valves failed. After failure analysis by the manufacturer, this was determined to be due to two possibilities- either erosion due to too much solids or corrosion caused by the foamer. The solids requirements specified by the manufacturer are NAS1638 class 9 specifications, which is quite stringent for oilfield applications and is not consistent with experience of others with these valves. Because of this the mesh size of the filters upstream of the pump was reduced down to 20 microns to protect the 3-way valves.

The other cause, corrosion, was presumed to be the most likely. A critical piece in the valve assembly was delivered in AISI 4140 steel, which is not a stainless steel as requested initially. It is likely that the failure of the valves was a result of corrosion due to the foamer in contact with this low alloy steel. The part was changed out to stainless steel.

From the combination of the lower mesh filters and the higher alloy internals no problems have been experienced with the 3-way valves.

5.2.6 MetersA coriolis meter for flow metering and a pressure transmitter are incorporated into the skid. The measurements are relayed to the PI system.

5.2.7 Pressure Safety ValvesTo avoid over pressuring of the skid, pressure safety valves (PSV’s) are installed in the discharge and suction of the pumps. These PSV’s are typically set to the minimum rating of the downstream equipment, which is typically ~300 bar.

5.2.8 Skid operationThe system can operate in 3 different modes:

Manual- in this mode the pump will turn regardless of other events or measurements in the system.

Foam injection- in this mode the foam injection is occurring at the desired rate. If the well is shut-in then the injection will automatically stop.

Hold SCSSV open- in this mode, the pressure is regulated between two preset values- the low-pressure setting and the high-pressure setting (LPS and HPS, respectively)- with the objective of holding the SCSSV open without injecting foam. If the pressure falls to the LPS, then the pump switches on until the HPS is reached, at which point it switches off again.

5.2.9 Defoamer SkidFor injection of low viscosity defoamers, a pump skid has been designed and deployed which differs from the foam pump skid in the following manners:

No 3-way valve No HPC/LPC function Maximum capacity of 15 ltr/d

For higher viscosity defoamers that are expected to be used in new installations, an air driven pump is currently being tested. Should this pump be successful, and then it may be applied and used in the future installations

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5.3 Results to DateSeven continuous foam systems have been installed to date. Of these 7, 4 are clearly successful, while the other 3 have not shown success. The criteria that contribute to the probability of success are discussed in section 7.

5.4 Well ExamplesThe following figure is an example of a successful well, MKZ-3:

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The red dashed line in the figure shows the time at which the well was put on continuous foam injection. What can be seen in the figure is that prior to the well being on continuous foam injection, the well could not produce stably and was only in production for very short periods on the order of days or less before dying. After the installation of continuous foam, the well flowed stably at more than 200,000 m3/d for approximately 9 months before suffering from a hydraulic leak in the X-mas tree.

Another successful example, WAV-18, is shown in the figure below:

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treated with batch foam as well. What can be seen here is that although the well produced rather stably prior to the continuous foam installation, the average production rate nearly doubled after installation of continuous foam.

Examples also exist for the 3 wells that did not show any reaction, in which the production behavior before and after was not changed.

5.5 Alternative Deployment SystemAn alternative system for deployment of continuous foam has been developed by Dynacoil (now BJ) and was recently deployed in a Gulf of Mexico well operated by Chevron-Texaco. The modified SCSSV for this system is shown in the figure below:

Locking Assembly

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This concept does not use the control line that is connected to the HWCU for delivery of foam, but rather makes use of a separate capillary string inserted through the X-mas tree that stings into a receptacle in the modified SCSSV. The foam is pumped through this upper capillary string, through the modified SCSSV, and then into the lower capillary string that transports the foam down to the injection depth.

In order to allow the upper capillary string to be run into the well, this concept does require modification of the X-mas tree design on surface so that the functionality of the actuated upper master is not compromised. An example of a X-mas tree modified for this concept is shown in the figure below:

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In this figure, the X-mas tree on the right is an unmodified X-mas tree, and the figure on the left shows the tree that has been modified to allow for the capillary string to feed into the well. The capillary string feeds in and passes under the actuated upper master valve, but does feed through the lower master valve4.

This system has some advantages and some disadvantages. The major advantage of the system is that the foam delivery is decoupled from the safety valve functionality. This means that in the case of leaks in the foam delivery system the SCSSV can still be held open for the well to produce. In addition, this concept does not have foam-wetted parts of low alloy metals which are susceptible to corrosion such as the 9Cr1Mo landing nipples that are part of the Halliburton system that NAM currently uses. The significance of this aspect is described in section 8.1.5.

The major disadvantage of this system is the requirement to modify the X-mas tree. This modification is likely to be expensive, and it also would have certain lead time requirements. In addition, multiple designs may be required for different wells.

4 Hartman, Larry, Bolding, Jeffrey, Microstring Technology in Conjunction with Subsurface Safety Valves, 1st European Gas Well Deliquification Conference, Zeegse, Netherlands, 20th September, 2006

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6 Candidate SelectionIndustry experience has been combined with in-house experience to develop current best practices for candidate selection. Some factors are directly linked to the ability to generate foam in the well, but once foam is successfully generated there are other factors that still must be taken into consideration to make a well successful.

6.1 Batch foamDepending on the environment where batch foam is desired to be applied, it may be easiest just to pump it and see what happens. This was the approach taken for the Land asset and may be applicable when there is commitment to long-term trials and there is possibility to vary chemicals and other parameters. In other, less flexible environments, such as offshore, it may be desired to try to maximize the POS before carrying out a trial or campaign in order to achieve the best results and demonstrate the need to continue with the batch foam jobs. The following are candidate selection tips gained from industry as well as experience in the Land Asset.

6.1.1 Water to condensate ratioProbably the most important factor for foam performance is the amount of water in the well and the amount of condensate in the well. This is widely mentioned in industry and NAM experience as well shows that this is important. This is usually referred to as the WCR. The foamers that are used are designed to generate foam in the water phase, and condensates act as natural defoamers.

While a firm cut-off cannot be given at this time for how high of a WCR is required for good foam generation, it is generally believed that at least a 3:1 WCR is required to make a good candidate. Experience in NAM shows that a 1:1 ratio is not foamable in practice with the foamers that have been tried to date.

6.1.2 Presence of downhole chemicalsDownhole chemicals that are applied for various reasons can also have large effects on foam performance. For NAM specifically, the downhole corrosion inhibitors that are sometimes injected via the SPM are known to be defoamers. This is shown in the figure below:

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Influence of corrosion inhibitor on foam performance

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Wells with downhole corrosion inhibition are not considered to be high probability of success (POS) candidates at this time. Results from batch foam also support these laboratory results. Of the wells with downhole corrosion inhibition that were tried with batch foam, no wells were evaluated as being successful.

6.1.3 Type of condensateIn addition to the amount of condensate relative to water, the properties of the condensate are also large factors. Condensates with heavier hydrocarbon fractions are observed in the lab to be much more of a defoamer than light hydrocarbon fractions. Significantly higher foam concentrations are required to achieve the same foam performance in the laboratory tests for wells with heavier condensate. In addition, some suppliers of defoamers add C15+ fractions to aid in the defoaming process.

6.1.4 Lab testing with sampled fluidsPrior to beginning foam in less flexible areas, it is essential that tests be carried out in the lab with sampled fluids representative of that particular well in order to make a judgment on foaming performance. There can be significant differences in the performance of different chemicals with fluids samples from specific wells. In addition, there may be quite varying fluid compositions across a certain field depending on the number of reservoirs that are produced in the area.

Foam testing in the laboratory is analyzed primarily on foam build-up time and break-down time of fluids representative of the fluids to be foamed downhole. This is described further in the chemical considerations section. An example of a foam test done with water from a Coevorden (COV) well are shown in the figure below:

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Foam stability (foam collaps time) COV-40 at 90 °C (3,2 % foam dose rate)with 10 and 30% condensate (liq vol intake 160 ml)

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In this figure, it can be seen that the foam stability of the different foamers, measured in terms of break-down time, is very different for the same water sample, and this should be used as a relative indicator of foam performance in such a well.

6.1.5 Total Dissolved SolidsWhile industry publications suggest that high levels of total dissolved solids may be detrimental to foam generation, NAM experience has not seen this to be a significant factor. Areas of high success such as WAV and MKZ have very saline brines, with TDS levels of 110,000 mg/l and 200,000 mg/l.

6.1.6 Suspended solidsDiscussion with vendors indicates that suspended solids in large quantities may be an issue for foam generation, but it has not been proven to be detrimental in NAM wells to this point. FeS was mentioned as a risk due to its likely presence on the tubing walls in the sour wells with carbon steel. However, there have been indications of positive results of foam application in sour wells.

A continuous foam string was installed in TUM-1, and while the production in the well did not increase significantly, formation water was produced to surface, which had never been measured before in this well. This was an indication of more water being lifted due to the foam injection, and it was later concluded that the lack of a production increase was due to the very tight nature of the well and its relative insensitivity to backpressure. ROW-2 also appears to be successful on batch foam treatments. TUM-1 and ROW-2 are both completed with carbon steel tubing and have H2S levels of 12,000 ppm and 3,000 ppm, respectively, so FeS will be present in the well. These two examples provide indications that foaming can be successful in wells where FeS is present.

6.2 Continuous foamContinuous foam installations require far more time and money investment than batch jobs. Therefore, there should always be a strong focus on candidate selection prior to executing an installation. The factors pointed out above should be investigated, and in addition there are some more factors below that should be evaluated as part of candidate selection.

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6.2.1 Success on batch foamIf a well shows a clearly successful reaction after batch foam treatments, it is considered to be a good candidate for continuous foam application. Should a well show clear success, it is still recommended to check some of the factors in this section to make sure that there are no inconsistencies with the other factors known to contribute to success.

Should a well not show good batch foam success, that does not necessarily mean that it is not a candidate for a capillary string. This has been experienced in WAV-18.

In the figure above, it can be seen that there was no clear response to any of the batch foam jobs pumped with the FoamerB chemical despite trying 4 different batch foam jobs and varying the volumes pumped. There was however success seen after pumping the FoamerE chemical in the well on several different occasions. The well was then put on continuous foam and showed a clear response to the FoamerB foaming chemistry (in a winterized version), despite not showing success with this chemical during batch applications. This clearly demonstrates that a lack of batch foam results due not necessarily mean that a well is not a good continuous foam candidate.

6.2.2 Critical rate will be lowered enoughWhen all of the right conditions are met and foam is generated downhole from the pumped surfactants, it is still required to have sufficient flow potential in the well to produce the newly formed fluids out of the well. As shown previously, industry literature as well as NAM experience shows that wells can flow stably at flow rates of up to 33% less than the previous critical rate. It should be known that the well would be able to provide an inflow of more than 66% of the critical rate at the system pressure that the well produces against.

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This can be simulated with some confidence in WePS depending on the WGR of the well. For low WGR’s, a dry gas curve can be simulated with the same inflow performance as the well currently has. This curve is an indication of what the well can produce at THP’s higher than the liquid loading point of the well. If the intersection of the THP and the P-Q curve is at a flow rate higher than the new critical rate, then this confirms that the well should be able to flow stably with foam generated downhole. This is demonstrated with the curve from WAV-18 below:

In this figure, the matched wet gas curve is shown along with the test points from periods before and after foam and a dry gas curve. While slightly off of the data points, the dry gas curve gives an indication of what the well produces with the foam injection at varying tubing head pressures.

6.2.3 Inflow performance optimized?Foam addresses an outflow problem. It should be confirmed that inflow performance is not significantly impaired as compared to previous testing prior to installing a continuous foam system. A HUD check should be carried out prior to selection of the well to confirm no sand fill or salt/scale in the well, and attempts should be made to confirm inflow performance by comparing the current IPR to previous data.

Often it is difficult to effectively judge the inflow performance of a liquid loaded well due to the unknown liquid hold-up that exists between the measured THP and the reservoir. Therefore it is very useful to run a flowing pressure survey or an echometer survey to determine the flowing bottom hole pressure during production. This flowing bottom hole pressure and production at the time can be compared to estimated IPR curves to judge whether or not the well is more or less in line with previous inflow performance. Such a survey can also help to quantify the gains from unloading the well by knowing the actual amount of incremental backpressure caused by liquid loading, and consequently the amount of incremental production that can be achieved by removing the liquid hold-up. An example of a flowing pressure gradient is shown in the blue line in the figure below:

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SCH-591 Flowing Pressure Survey

0

500

1000

1500

2000

2500

3000

3500

4000

0 10 20 30 40 50 60

Pressure (bar)

Mea

sure

d de

pth

(m)

Guage Pressure,measured (bar)Dry gas, 50,000 3m/d,calcWet gas , 100,000 m 3/d,calc

This survey from SCH-591 serves several purposes. First, it confirms that the well is suffering from liquid loading. A normal gas production gradient is observed for the first ~500 meters, while from that point down a gradient of ~0.15 bar/10 m is measured. The well was at this time flowing 50,000 m3/d through a 5” tubing, so it is not possible that this pressure drop is due to friction. Two other curves were calculated with WePS to demonstrate what expected bottomhole pressures would be with an unloaded well. For a well flowing 100,000 m3/d (above critical rate), the bottomhole pressure is estimated to be ~20 bar. Therefore more than 30 bar could be lifted off the reservoir by removing the liquid hold-up.

The FBHP from the survey along with the flow rate at the time can be compared with the IPR of the well or can be used to create an IPR for the well. An example of this is shown below:

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Flowing survey match

Estimated inflow if unloaded

Flowing survey match

Estimated inflow if unloaded

For the SCH-591 case, the FBHP measured is shown on the IPR curve and a good match is obtained to the data from previous tests. Without liquid loading, a bottomhole pressure of ~25 bar or lower is expected with a FTHP of 15 bar. This new point on the IPR gives an indication of what the inflow will be from the reservoir if the liquid hold-up is removed and what gains can be expected should foam be generated downhole.

6.2.4 Wellbore accessAccess to the desired setting depth should be confirmed prior to selecting the well for continuous foam. Fish or any other restrictions should be known.

6.2.5 Temporary test well candidate?In some cases, it may be desired to carry out a temporary test of continuous foam injection with a capillary string. This is carried out by running a capillary string into the well and injecting foam, typically as a continuous operation for a period of 4-5 days. Because the SCSSV is not operational, this must be a manned operation for 24 hours a day. An estimate of the costs for this in a Land Asset operation is ~ € xxx for a 5-day test.

Not all wells are good candidates for a temporary test. For the money and resources that it requires, it is not desired to have an inconclusive test. Therefore, a candidate should be selected that will let a conclusion be drawn after 5 days. Wells that consistently load up and die within 1-2 days would make good candidates for a test. However, some wells may flow for a period of more than a week before loading up. These wells would not make good candidates for a 5-day test. Wells that have a problem kicking off are also not considered good candidates for a test. An example of a good test candidate, COV-53, is shown in the figure below:

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Hourly 24-Dec-05 5:59:18 PM

15-12-05 16-12-05 17-12-05 18-12-05 19-12-05 20-12-05 21-12-05 22-12-05 23-12-05 24-12-05

COV24-FR-4-35-1

NM3/D COV24-PT-4-35-1

barg

20000

40000

60000

80000

1.E+05

0

1.2E+05

16.667

33.333

50

66.667

83.333

0

1001.4921E-12

15.999

COV24-FR-4-35-1

NM3/D COV24-PT-4-35-1

barg

It can be seen in the figure that when the well comes on stream it consistently dies within one day. Therefore, if the well would be able to produce for several days with a continuous foam test, then it would be very conclusive that the well had responded.

6.3 Closing RemarksThe criteria mentioned in this section are known from field experience and/or laboratory testing to have influence on the probability of success of foam applications. A trial and error approach to foaming may be appropriate when in situations where there is sufficient flexibility to try different chemicals and wells. However, when in an environment with a lack of flexibility or higher costs, these criteria should always be checked.

A positive result from batch foam tests is an excellent indication that a well should be successful on continuous foam, but should not be used as a requirement to put a well on continuous foam. At least one example exists where a well did not have success on batch foam with a certain foamer and was later successful on continuous foam with that same foamer.

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7 Chemical considerationsThe three main suppliers of foamers and defoamers to NAM are VendorA, VendorB and VendorC. Initially one VendorA product, FoamerC, and one VendorB product, FoamerJ, were selected as the preferred foamers for all wells based on some laboratory testing against certain criteria such as foaming tendency and emulsions. After some months of trying these foamers, there was a drive to try new foamers in areas where no success was observed from the original preferred products. In addition, many problems arose due to corrosion of downhole equipment resulting from dissolved oxygen in the foamers.

The desire to increase success rates as well as the problems experienced with corrosion led to the use of several different foam products and the introduction of another vendor, VendorC. Experience with the different products has been gained over time and resulted in identification of key parameters that are important when selecting a foamer for a given application. A complete list of criteria that must be satisfied has been prepared by production chemistry5, and the following parameters are regarded as the most important for the foam project.

7.1 Foamer Requirements

7.1.1 Foaming AbilityThe purpose of pumping the foamer is to generate foam between the water and gas phases, which is easier to lift out of the well than the water alone. The foaming ability is typically evaluated in terms of the foam build-up time and also the foam breakdown time. Detailed foam testing procedures are specified in the NAM foam testing document6. Different foamers will show different results in terms of foam build-up and breakdown times, and this also varies with the produced fluids tested.

It is desired to have a good build-up of foam from the initial starting point of 200 mL. Typically, the foam height after 2 minutes will be measured, or the time it takes to build up to 1000 mL in a graduated cylinder. The foam build-up is an indication of how well foam is generated with a given foamer and water sample. The other parameter, foam breakdown time, has varying opinions. Some vendors claim that a longer breakdown time is preferred over a foam that breaks down very quickly in order to ensure that the mixture remains foamed throughout the well. However, other vendors claim that it is desired to have a quick breakdown time to ensure that there is no foam present when the mixture reaches the facilities. To date, NAM has been focussed on longer breakdown times to ensure maximum POS of unloading the well.

It is very important that the testing represents downhole conditions in the well that is being considered for foam. This means that the sample of fluids used as well as the testing conditions must be representative of what is downhole. Obtaining representative samples can be challenging at times. Depending on the location of a sample point, chemicals may be injected upstream (i.e. surface corrosion inhibition) which will influence the foam testing and provide results that are not representative. In addition, there may be no sample point at all, or it may be in a separator where several wells flow together. Samples can also be obtained in some cases with a downhole bailer, or with a temporary separator from well services.

In addition to the sample being representative, the conditions at which the test is carried out must reflect what is downhole as much as possible. Temperature can have a significant effect on the results of a test, and foamers typically tend to perform worse at higher temperatures.

From all testing carried out in NAM as well as field experience, some foamers have emerged as being stronger than others for a wide range of fluids. For instance, the FoamerH and FoamerI foamers have consistently shown better laboratory results than the previously preferred FoamerC foamer. The effects of this product in the field vs the FoamerC field experience is still being evaluated in terms of

5 contact Gert de Vries for details6 contact Gert de Vries for details

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whether or not any results are seen in areas where no results were seen with the FoamerC. The earlier example of WAV-18 showed that while there were no results on batch foam with FoamerB, there was clear batch foam success with FoamerE.

7.1.2 No solidsDue to the injection system used to deploy continuous foam, solids should be avoided. Lack of focus on this issue on WAV-18 resulted in a plugging of the downhole injection valve in the first few days of injection. Solids can also cause erosion of equipment. The filter on the pump skid serves as a protection against solids, but solids should still be minimized to avoid down-time and operator intervention for replacing fouled filters.

Solids can be either present in the foamer when delivered or they can be a result of processes such as corrosion that may take place in on-site storage tanks or the equipment that the foam travels through on the way downhole. In the WAV-18 case, solids were caused by corrosion of the carbon steel storage tank that was used.

There was also previous experience with solids in the FoamerC foamer due to lack of quality control on the sourcing of additives to the foamer. This was detected at the supplier and had most likely been the root cause of some equipment malfunction and frequent filter plugging on one well. For this reason, excessive filter fouling should be investigated, as it may be an indication of impurities in the foamer.

7.1.3 WinterizedAll products used in NAM must be winterized to –20 C. This is typically catered for in foamer products by the addition of glycol, methanol or isopropanol. The chemical supplier is responsible for addition of these components, and mixing or addition of chemicals to foamers should not be attempted by NAM.

7.1.4 Thermal stabilityDifferent types of foamers have different levels of thermal stability. Amphoteric foamers are typically thermally stable to temperatures of up to 200 C, while other types of foamers such as anionic or cationic are typically stable to less than 100 C. When a foamer is taken beyond this thermal stability point, the product splits into separate phases. This can be seen in the picture below:

In this case the FoamerD is shown in normal conditions without being exposed to higher temperature on the left, and the middle and right samples have each been exposed to 125 C for a period of 1 day. Foaming performance is lost after the phase separation and more importantly the phases that result are typically low pH acidic components. The pH of the different layers were each less than 1, and even when 10% of the phases is mixed with water to simulate downhole conditions, the pH remains

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close to 1. These components are clearly not desired in the well due to the acidic nature, and they can also mix with formation water to form sulphate scale by-products.

The picture below shows the potential effects of the low pH fluids on the equipment in a well:

The picture shows the upper part of the double back pressure valve installed at the end of the capillary string that was removed from COV-55 (top) and a new upper part of the valve (bottom). The damage to this piece of the valve is clear, and more importantly, the remaining parts of the valve that are screwed onto this piece were completely gone. The bottomhole temperature in this well is approximately 102 C, and several foamers were used which had a thermal stability of less than 90 C. It was concluded that the damage to this valve was the result of corrosion from the acidic components that were formed due to breakdown of the foamers used under the temperature conditions in the well.

The thermal stability of the foamers that have been used to date are as follows:

Foamer Deg CFoamerF 82FoamerE 82FoamerB 204FoamerC 204FoamerD 90FoamerI >130FoamerH >130

7.1.5 Non-corrosiveThe foamer fluids can contain dissolved oxygen of up to 7 ppm as measured in the laboratory. This dissolved oxygen has been the source of extreme corrosion that has been observed in certain components in the wells. This has also been demonstrated in lab tests. The corrosion due to this oxygen is a problem in what is referred to as the “foam wetted” parts of the installations. Foam wetted parts are parts where only foam is the fluid in contact with a material, and there is no mixing with other fluids from the well. These parts include everything from the IBC tanks to the double backpressure valve that is at the end of the capillary string.

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Corrosion due to oxygen is not expected to be a problem in the well after passing through the double backpressure valve. This is because the 7 ppm of oxygen in the relatively low volumes that are injected (15 ltr/d) will be combined with the flow from the well and will be diluted down to the ppb or ppt levels that are not considered an issue for oxygen corrosion.

Oxygen corrosion has been observed on all metallurgies that are not stainless steels. This means that anything less than a 13% chrome content will show corrosion. Initial versions of valves used materials such as 9Cr1Mo and also lower alloys such as 42CrMo4, which is the same quality as carbon steel such as AISI 4140 (despite the misleading “42Cr” in the name). These components showed significant corrosion and were determined to be not qualified for use in the installations. A picture of the 42CrMo4 pulled out of MKZ-3 is shown in the picture below:

An example of pitting from a 9Cr1Mo piece pulled from WAV-18 is shown in the figure below:

The pits can be clearly seen in the 9Cr1Mo material of the valve. When certain parts are taken into account that are exposed to both the well fluids on one side and are foam wetted on the other side, it is required to have high nickel materials to prevent sulfide stress cracking in sour environments on the 13Cr or similar alloys. This requires metallurgy such as incoloy.

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This situation is a problem due to several reasons. First, higher alloy metallurgies such as incoloy are more expensive and have longer lead times. More importantly, the landing nipples in the majority of wells in the land asset are made of 9Cr1Mo. These landing nipples cannot be changed without a workover, which is not economic in the majority of wells in the population of liquid loading. Excessive corrosion over long periods of time could lead to a leak of the landing nipple, which would prevent operation of a SCSSV and would prevent any further production from a given well. This is considered unacceptable.

Fortunately, not all foamers show oxygen corrosion. FoamerI has a specially added chemical from the vendor to prevent oxygen corrosion. An example of FoamerI and a VendorA foamer (FoamerC) are shown in the picture below:

It can be clearly seen that the FoamerC gives much corrosion while the FoamerI sample remains in perfect condition.

Work is currently ongoing with VendorA to develop foamers that are not corrosive for dissolved oxygen.

7.1.6 Elastomer compatibilityDue to the importance of holding pressure in our foam deployment system, the foam must be compatible with the elastomers used as pressure seals in the assembly. All elastomers that are used downhole are made of Kalrez (or Halliburton’s version, Ryton), and the surface equipment contains various types of Viton and NBR. Damage from foamers to lower grade elastomers was suspected in some early installations, and therefore it was decided that only Viton or higher grades of elastomers would be used in the downhole equipment. Since that time, there have been no cases where elastomers have been adversely affected by the foam fluids pumped into the well.

7.1.7 EmulsionsEmulsions are highly likely to be formed when foam is introduced into the mixture of water and condensate coming from the wells. This has been confirmed with testing of various products and various mixtures of water and condensate and also observed in the field. An example of some laboratory testing is shown in the figure below:

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The figure shows several samples of water and condensate, with or without foam added. The samples were shaken and then observed for a certain period of time. From this picture, it can be seen that for both salt water and sweet water a layer of water in condensate emulsion is present as well as a hazy water phase indicating a condensate in water emulsion. The effect of different foamers on oil in water is shown in the figure below:

Mineral oil contant (incl. aromatics) in waterphase

0

200

400

600

800

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1200

1400

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1800

2000

Blanco FMW 3064 CDM 736 Blanco FMW 3064 CDM 736

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l)

4ml

8 ml

8 ml

4 ml

4 ml

+ defoamer

+ defoamer

4 ml

8 ml 4 ml

8 ml

+ defoamer

+ defoamer

0,05 % NaCl 10 % NaCl

Foamer B Foamer J Foamer J Foamer B

In this figure, the amount of oil in water is tested in samples with no foam as well as two different types of foamers- FoamerB and FoamerJ. Both of the foamers resulted in increased oil in water

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measurements, and the addition of defoamer showed no influence on the results. What can be seen here is that the amount of emulsion created was different for the different types of foam used, and this must be taken into account when selecting a foam for a given application. In addition to the type of foam, the concentration of foam injected also has a significant effect on the tendency to form emulsions. Overdosing of foamers has led to emulsions being formed in the lab as well as in the field that are worse than what is observed at lower concentrations.

7.1.8 Water in condensate emulsionsChemicals have been tested in the lab and also used in the field to treat problems with water in condensate emulsions resulting from overdosing applications. While certain chemicals have proven to be effective, a universal solution does not exist and a suitable demulsifier would need to be identified for applications involving different water and condensate compositions and different foamers.

7.1.9 Condensate in water emulsionsThe ability to reduce or eliminate condensate in water emulsions is of particular importance to offshore applications of foam where overboard discharge is the only available means of water disposal. For condensate in water emulsions, no chemical has been identified yet that can be used to reduce OIW levels to what is acceptable for overboard discharge on offshore installations. This does not mean that it is not possible, but this has not been an area of focus to date for the primarily land based project.

7.2 Compatibilities of foamers with other fluidsShould it be desired to change foam during operation, one foamer may come in contact with another foamer in the delivery system or downhole. Compatibility of these fluids then becomes an important issue. Compatibility testing was carried out in the laboratory at –5, 20 and 70 C, and the resulting compatibility of different foamers is shown in the table below:

MacGel A MacGel BUnivis HVI

13 FoamerB FoamerC FoamerE FoamerG FoamerD FoamerH FoamerIFoamerB FoamerC * FoamerE * * FoamerG FoamerD FoamerH FoamerI FoamerJ

Okay Not tested Not to be mixed

* Not tested at -5 C

Foamers have been pumped in contact with each other with minimal negative consequences to date. However, this chart should be consulted any time such a change would be necessary to ensure that no reactions take place which may lead to a blocked control line or capillary string in the well.

Special care needs to be given to mixing of foamers with hydraulic oil. Univis HVI is the hydraulic oil used in the land asset and has been shown to not be compatible with certain foamers, particularly the FoamerI which is the preferred foamer for continuous foam applications at this time. Mixing of foamers and hydraulic oil is not recommended, and a spacer should be pumped in between the two to ensure this does not happen when the system is switched from one fluid to the other. Mac-Gel is the

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currently selected product that has been used and should be used in the future for all chemical change-outs in the system. The performance of glycol and other generic products is currently being investigated in the lab for use as a spacer.

7.3 DefoamersDefoamers may be required on certain locations to prevent upsets in the facilities downstream of the well. The approach taken to date has been that all locations where processing facilities exist (compressors, glycol dehydration, etc.) require the use of defoamer, and all satellite locations do not require defoamer. No problems have been experienced due to batch or continuous foam on satellite locations to date. For locations with facilities, one problem was observed on TUM-1, where continuous foam and defoamer were injected.

After several months of continuous foam injection on TUM-1, the glycol burner suffered problems and had to be replaced. The root cause of the problems was determined to be salt in the glycol system due to carryover of saline production water from the separator into the glycol system. Defoamer was injected during the whole operation, but it was later discovered that the defoamer used in this application, which was the standard defoamer used in the project to date, was not strong enough to defoam some of the stronger foamers that were being tried on various wells including TUM-1. Other factors which contributed to this carryover is the fact that this location only has one well feeding into the glycol system, and the separator is most likely already operating out of its performance envelope. However, there were no reports of salt in the glycol system prior to foam injection.

Lab tests following this incident confirmed that the defoamer being used was not strong enough against certain foamers in the portfolio, particularly FoamerD and FoamerI. A market search has taken place to identify suitable defoamers for use against our higher strength foamers. This has been complicated by the following factors:

Ineffectiveness: many of the defoamers that have been tried do not show effective defoaming against the foamers mentioned

Silicon oil: defoamers frequently contain silicon oil, and this is not allowed to be used due to commercial agreements with our downstream refineries that our condensate is shipped to. The silicon oil destroys the catalysts in the process.

High viscosity: many of the defoamers available on the market are highly viscous, which complicates the possible delivery methods

One defoamer has been identified that does not contain silicon oil and is effective against all foamers in our portfolio. This product is called DeFoamerA and is supplied by VendorB. However, this product is still highly viscous and also is not winterized to NAM standards. It is therefore required to heat trace any application of this during the wintertime. In addition to preventing freezing, the heat tracing helps to ensure that the viscosity does not become too high during cold periods. More work is still ongoing to identify suitable defoamers for high-strength foamers.

7.4 Foamer Portfolio and Preferred ProductsSeveral different foamers have been tried to date in NAM. The foamers have varying pros and cons, some of which are more important for batch or for continuous foam. Based on the issues described earlier in this section, the foamers have been summarized in the following table:

Foamer Performance

Oxygen corrosion* Winterized

Thermally stable (135 C)

Solids contamination Emulsions Defoamer

FoamerJ DeFoamerA**FoamerB DeFoamerB***FoamerC DeFoamerB***FoamerA DeFoamerB***FoamerF DeFoamerA**FoamerE DeFoamerA**

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FoamerD DeFoamerA**FoamerH DeFoamerA**FoamerI DeFoamerA**

Poor performance Medium performance Good performance

* Only an issue for continuous foam applications** May not be practical for batch application, but can be used for continuous installations*** Easily pumpable and winterized for batch applications

7.4.1 Preferred batch foamer (satellite locations)The oxygen corrosion is not considered to be an issue for batch jobs, only for foam-wetted areas of continuous foam installations. For satellite locations where there are no facilities, foamers that meet the thermal stability requirements of the wells should be tested with live fluid samples from the wells to determine which chemical gives the highest POS for unloading the well. Should no fluid samples be available, FoamerI would be the recommended chemical. This chemical has consistently shown better foam performance in lab tests than the others in the portfolio.

7.4.2 Preferred batch foamer (locations with facilities)For locations with facilities, defoamer is required. Depending on availability of pumps for high viscous pumping and the weather at the time, it may be possible to follow the same procedure as recommended for the batch foam on satellite locations. However, on the Land Asset it has been decided that only FoamerA will be used on locations with facilities for the time being due to impracticality of having a mobile, heat-traced defoamer skid for use during all times of the year.

7.4.3 Preferred continuous foamerFoamerI is the preferred continuous foam chemical at this time due to the fact that it is the only chemical that has shown no oxygen corrosion in lab tests or in the field. The major drawback to this foamer is the fact that it is a strong foamer, and the only defoamer available that works is the highly viscous, not-winterized DeFoamerA. This can be managed by heat tracing a semi-permanent continuous foam installation.

7.5 Further DevelopmentsOne area being investigated is the development of a chemical that acts as a foamer as well as a CO2 corrosion inhibitor. Some work was initiated on this earlier in the project, but it was not progressed due to the oxygen corrosion problems that were observed with the foamers. This work is now being picked up again with the foamers that have shown protection against oxygen.

In addition to this, work is still ongoing to identify better defoamers.

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8 Materials ConsiderationsThe materials that are required for operation with continuous foam injection are determined by the fluids that come in contact with the hardware. For some parts in the foam delivery system, the foam itself is the only fluid in contact with the material. However, for some parts of the chemical injection valve the materials are exposed to the well fluids as well.

8.1 Well Fluid ExposureThe well fluids can vary depending on the reservoirs of production. The wells have been broken down into 3 main categories:

Non-corrosive: very little/no CO2 and no H2S Corrosive, sweet: corrosive for CO2 conditions, not sour (< 3.5 mbar H2S partial pressure) Corrosive, sour: corrosive conditions for CO2, sour service (>3.5 mbar H2S partial pressure)

These categories define the two categories of materials standardly used for our valves now. The non-corrosive and sweet corrosive categories have been merged into a valve design that consists primarily of 9Cr1Mo and 17-4 PH. The wells that are corrosive for CO2 and are sour service are made of incoloy. While it is recommended to use stainless steels for all areas of the system, 9Cr1Mo has been chosen for use in some of the subsurface valves. This is due to a desire to save cost and simplify the downhole equipment after the non-corrosive foamer was identified.

8.2 IBC tanksThe storage tanks for foam that are currently used are IBC containers that are made of stainless steel 304. This prevents any possible corrosion by products from the foam. An earlier installation on WAV-18 made use of an old carbon steel methanol storage tank, and the resulting quality of foam that was being put into the system was completely filled with corrosion by-products. A picture of foam sampled from the tank can be seen in the figure below:

In order to prevent this and to ensure as clean of foam as possible, only stainless steel IBC tanks are currently used.

8.3 Other surface equipmentIn addition to the IBC tanks, the pump, all lines and instruments are made up of various types of stainless steel (304, 316, Incoloy 925, etc). No carbon steel components should be used in the foam system due to the potential for corrosion.

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8.4 Filter foulingAs mentioned previously, a filter with a 20 micron mesh size is used upstream of the pump. This filter has become clogged regularly on some wells and has required replacement. A picture of a dirty (left) and clean (right) filter are shown in the figure below:

The solids clogging the filter consist mostly of iron and are likely the result of some corrosion taking place. This appears to be occurring in small amounts despite the use of stainless steels upstream of the filters. However, after changing to the FoamerI on these locations, the filters have not required replacement, thus reinforcing the non-corrosive nature of the FoamerI.

8.5 Elastomer CompatibilityAs mentioned previously, the foam must be compatible with the elastomers used as pressure seals in the assembly. Damage to elastomers was observed in the beginning of the project on two different installations. In WAV-18 the O-ring that moves inside the chamber of the double backpressure valve was found to be badly damaged, and an O ring in the COV-55 assembly was found to be damaged and leaking as well after being pulled and examined in the workshop.

The cause of the failures was suspected to be due to mechanical design flaws or possibly to chemical attack of elastomers such as EPDM. As part of the failure investigation, elastomer testing was carried out in the NAM laboratory, and more advanced testing was carried out by a supplier of elastomers to measure changes to physical and chemical properties. The equipment was redesigned and it was decided only to use Viton or higher quality elastomers in all subsurface equipment. Since the redesign of the equipment and the switch to higher-grade elastomers, more experience has been gained with the systems, and no issues with elastomers on surface or downhole have been observed. This includes a mix of Kalrez (or Halliburton’s version, Ryton) downhole, and various types of Viton and NBR on surface.

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9 Installation

9.1 Pre-installation (HUD check)Prior to installation, the hold up depth in the well should always be checked far enough in advance that remedial action can be taken if necessary. This helps to eliminate surprises on the day of installation of the components.

9.2 ProcedureA typical high-level outline of an installation is given below, and the numbers in parenthesis reference graphical representation of the steps shown in Appendix 2:

1. Rig up NAM W/L (1)2. Pull SCSSV from landing nipple (2)3. Tag HUD and record depth4. Rig down W/L5. Rig up BJ quad BOP, injector head, stuffing box, and capillary string truck6. RIH cap string along with double back pressure valve, stem and spring nose (3)7. Perform pull tests every 500 meters8. Tag HUD and space out to desired setting depth9. From setting depth, pull up distance equal to depth of LNSV (+ 1-2 meters)10. Close pipe rams and slip rams (4)11. Bleed off pressure12. Remove stuffing box13. Attach mechanical slip device on top of quad BOP14. Cut capillary string15. Attach modified SCSSV to capillary string (5)16. Rig down BJ cap string truck 17. Rig up NAM W/L18. Attach running wireline toolstring to modified SCSSV assembly19. Screw lubricator onto quad BOP20. Release pipe rams and slip rams21. Run down to LNSV22. Set modified SCSSV in LNSV (6)23. Rig down NAM W/L

This procedure is valid for LNSV up to 3.813”. For installations of larger size, an insert sleeve is required to be set first.

9.3 Setting depthThe setting depth for the coil is specified before the job and is typically based on examination of PLT data or flowing pressure surveys if they exist. There is no clear rules for where to set the injection point in the industry, but within NAM it is preferred to set the coil above at least 50% of the inflow to ensure that the foam is taken upward in the well. A flowing survey can help to identify the amount of backpressure that can be reduced off the formation by removing liquid hold-up at different setting depths.

Production performance is not the only consideration for the setting depth. For wells with sand production, erosion can occur on the capillary string or components hung on the bottom of the string. This was seen in MKZ-3 and is shown in the figures below:

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In this picture it can be seen that a hole was created in the capillary string, and the components below that point were eroded as well. The string is made of incoloy 625, so corrosion is highly unlikely. The capillary string was also filled with sand in the lower part, which suggests that the hole was created by erosion from sand production. Due to this risk, it may be desired to set the capillary string just above the perforations for wells where sand production is expected.

To achieve the desired setting depth during installation, HUD is first tagged and recorded with the slickline unit after pulling the flapper valve. The HUD is then tagged again with the capillary string, and it is spaced out to the desired setting depth. This tag and space-out method is the most accurate way to land the end of the coil at the desired setting depth. Although several improvements have been made since the first installations, the counter used in the capillary string truck itself is still considered to not be very accurate. In one example, the proper procedure was not followed and it resulted in the capillary string being set approximately 1000 meters above the desired injection point.

9.4 Fluid flushing (mac-gel)In order to ensure that all of the hydraulic oil is flushed out of the system and that there is no interaction of foam and hydraulic oil, which can be incompatible, the system should be flushed with a product called Mac-gel or a similar chemical approved by production chemistry.

9.5 Start-upWhen all equipment has been installed and function tested, the system is ready to be started up. Typically a volume of ~25 liters of foam is pumped in the well through the modified SCSSV with the well closed-in to aid in kicking the well off. The well is then opened up to the facilities and started with the desired continuous injection rate.

9.6 Injection rateThe injection rate that is specified in the beginning is typically based on a concentration of ~0.1% volume of foam per volume of water to be lifted. If good data is not available on water gas ratios, then an estimate must be made for the initial injection period that can be optimized later.

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10 Post-installation MaintenanceAfter installation of a foam system, attention is still required to keep them running and functioning at optimum levels. The following are some of the aspects that commonly require attention:

10.1 LeaksPressure maintenance in the system is clearly required to allow the system to function. Should any leak paths occur anywhere in between the IBC containers and the LK-2 injection valve in the well, then the foam is not going to be injected where desired, and the modified SCSSV will most likely not be able to be held open. This means that not only will foam not be injected, but also the well will not even be able to be produced intermittently while this equipment remains in the well.

There have been several random leaks that have occurred on surface and are not attributed to the foam in any way. However, multiple cases of leakage have occurred due to problems with the LK-2 valve. The problems have ranged from leaking bellows within the valve to mechanical failure of the seat of the valve, which has not been experienced in NAM before and is currently being investigated.

A leak in the system can be clearly seen with the PI injection data. A leak is typically characterized by a decrease in the injection pressure and an increase in the injection rate. An example can be seen in the figure below:

Hourly 29-Mar-06 7:32:40 PM

14-3-06 16-3-06 18-3-06 20-3-06 22-3-06 24-3-06 25-3-06 27-3-06

WAV13-FR-4-18-1

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barg WAV13-FI-17

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Hourly 29-Mar-06 7:32:40 PM

14-3-06 16-3-06 18-3-06 20-3-06 22-3-06 24-3-06 25-3-06 27-3-06

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barg WAV13-FI-17

l/d WAV13-PI-17

bar

In this figure, the circled area shows that the injection pressure goes down while the injection rate goes up. Another indicator is that the production rate goes back down from 25,000 m3/d to 12,000 m3/d, which is the liquid loaded production of the well. This indicates that not all foam is getting down to the injection point and is most likely leaking out somewhere at the SCSSV level or above.

The typical steps to be taken when a leak is observed in the data is the following:1. Discuss with operations if they already know of anything wrong with the well2. Have operations close the valve of the control line going to the well at the wellhead3. Test the surface system by pressuring up with the pump to confirm no leakage on surface4. Go to location with well services stand-alone pump to test downhole equipment independent

of surface system

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5. If a downhole problem is confirmed, wireline and possibly the capillary string truck must be planned in to replace the leaking equipment

For a system installed with a 2.75” or 3.813” flapper valve, it will not be required to pull the capillary string to fix a leak. All pressure in the system is maintained by the LK-2 valve which sits in the modified SCSSV that is installed. The downhole double-back pressure valve serves only to provide two barriers during running and to try to keep the coil filled with foam to avoid creating a vacuum. It does not serve to regulate pressure in the injection system. For wells with landing nipples larger than 3.813”, the insert sleeve is required. The insert sleeve is a possible source of a leak path, and in a worst case it would be required to be pulled and reinstalled. This would require the whole capillary string to be pulled from the well so that the insert sleeve can be pulled and reinstalled.

To fix a problem with an LK-2, the whole system does not need to be pulled. A typical operation to repair a leak is the following:

1. Rig up BJ Quad BOP2. Rig up NAM W/L3. Pull modified SCSSV from LNSV4. Hang capillary string in BJ Quad BOP5. Remove lubricator6. Cut capillary string and remove modified SCSSV7. Install new modified SCSSV8. Test new assembly with pump at surface9. Replace lubricator10. Run modified SCSSV to LNSV

10.2 Filter pluggingThe filters upstream of the pump have been required to be pulled and replaced several times during the run-life of the current systems. This was due to some light corrosion that was taking place in the system upstream of the filter. Since the wells have been switched to the non-corrosive foamer, Tri-foam 820 Block, it appears that there has been no plugging of the filters.

10.3 Injection rate monitoring/samplingOptimization of the foam injection rate is very important to minimize any emulsions formed as well as the potential for foam in the installations. There are different methods for this optimization. The easiest method is to simply lower the injection rate and monitor the effect on the production of the well. However, this may result in loading up of the well if the rate is lowered too much, and depending on the availability of personnel to adjust the rate it may stay loaded for a several days.

In order to prevent lowering the injection rate too much, a good sampling and analysis routine, if possible, can help the optimization process. Samples of the produced fluids can be taken and then without adding any chemicals a foaming tendency test can be carried out in the lab. Based on the resulting foam build-up time and especially foam stability, it can be determined whether there is scope to lower the injection rate. This method was successfully carried out on WAV-18 previously.

10.4 Changing foamShould it be desired to change foams during operation, special attention should be given to mixing of the different foamers to avoid incompatibilities. A suitable spacer such as Mac-gel should be used between the different foamers to prevent mixing. The IBC container should be fully removed and a new one placed with the new foamer. Mixing of different foamers in IBC’s is not recommended.

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10.5 “Abandoning” a foam wellShould an installation not be successful and it is desired to go back to operations with a normal flapper valve, certain steps must be taken. Obviously the subsurface equipment will need to be pulled, and it is normally desired to switch back to the previous hydraulic well control unit as well. These events can be done independent of each other. For instance, a normal flapper can be installed and operated with foam as the hydraulic fluid with the foam surface installations while awaiting the change back to the old system.

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11 Cost Overview

11.1 Batch Foam Cost BreakdownBased on allocated costs to the batch foam jobs carried out to date, an average cost of € xxx per batch foam job can be expected for Land based operations. The cost will vary per well depending on whether or not other wells can be serviced on the same day. By pumping on more wells in one day, the costs of the whole day of a man and the batch foam truck are split over more wells.

11.2 Continuous Foam Cost BreakdownA cost breakdown for a typical initial installation of continuous foam is given in the following table:

Cost Element EurosSurface Modifications x

Well Services (W/L, cap string inst) xHardware (sleeve) x

Capillary string xCoiled Tubing Services x

Contingency Costs (~15%) xTotals € x

In addition to these initial installation costs, OPEX will be spent on chemicals as well as possible maintenance to the installations.

The example breakdown provided here is for a specific well, and costs of other installations will vary depending on the specific type of equipment required. These elements are discussed in the sections below:

11.3 Surface modificationsThe approximate cost for surface modifications including all engineering, civil works, instrumentation and the construction of a foam pump skid is ~ € xxx. Should a defoamer skid be required, the total costs are estimated to be ~ € xxx.

11.4 Capillary stringThe capillary string cost is dependent on the total length required for a given well. Capillary string costs are ~ € x per meter.

11.5 Modified SCSSVThe costs vary for the modified SCSSV depending on what size and type of valve is required. The costs range from € xxx up to € xxx. Factors that influence the cost are the size, materials, and other special requirements such as installation extensions for converted tubing-retrievable safety valves or modifications for deep-set safety valves. New designs and part numbers that do not currently exist also carry some initial engineering and tooling costs that may give a higher cost for the first valves of that type.

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11.6 Subsurface InstallationThe actual subsurface installation consists of NAM wireline and BJ resources. It is typically a two-day job with the standard day rates applicable.

11.7 ChemicalsThe OPEX associated with chemical costs can be significant depending on the amount of foamer required for a well. The foamer chemicals typically cost ~ € x per liter. For a well using 5 ltr/day of foamer, this amounts to ~ € xxx per year spent on chemicals assuming that the well produces 365 days a year. With the same assumption and a 100 liter per day injection rate (as used in MKZ-3), the chemical costs are close to € xxx per year.

11.8 Maintenance/Post-installation servicesAs described in the previous section, some post-installation maintenance may be required for fixing leaks or replacing small components in the system. A typical leak fixing operation costs € xxx. Other factors to consider is that any downhole issues such as tubing leaks, leaking dummies in SPM’s or any situation that requires safeguarding of a well may require the subsurface equipment to be pulled and possibly reinstalled later.

11.9 Costs to date of Land installationsThe costs to date of the seven installations on land were summed up recently. An average cost, including chemicals, of ~ € xxx was calculated. This was high due to some initial learnings that are not expected to be repeated, but it gives an overall idea of what an installation can cost.

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Appendix 1: Original Equipment Design for 5” & 7” tubing

This design consisted of an insert sleeve, which was placed in the LNSV. The capillary string was hung off of a BKLK-2 valve that sits in the bottom of the insert sleeve. A standard flapper valve was

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then run into the insert sleeve. Flow from the well would travel through the flow ports in the bottom of the insert sleeve and then up through the flapper to surface. The foam would be injected through the control line from surface, through the LNSV and into the insert sleeve, and it would then travel through the insert sleeve into the LK-2 injection valve and then into the capillary string. This version was not supplied by Halliburton, but instead was designed by NAM and machined locally.

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Appendix 2: Installation Procedure for Modified SCSSV (up to 3.813”)

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Appendix 3: Process Engineering Flow Scheme Example

foam lifting manual

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