2015-ATSE-SPE-SAS-138-Presentation

Saudi Aramco: Public Saudi Aramco: Public

SPE-SAS-138 : Innovative Coiled Tubing Deployed Zonal Isolation of a Highly Permeable Acid

Fractured Carbonate Reservoir in Saudi Arabia

Syed Muhammed Danish, Angel Arenas and Keshan Deonarine, Halliburton

Harmohan Gill, Ronald Morris and Prasad Karadkar, Saudi Aramco

4/13/2015 SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish 1

Saudi Aramco: Public

Agenda

• Objective • Oil & Gas Exploration • Drilling &Workover Challenge • Well X Data • Planned Execution • Design Considerations • Best Practices • Execution Schedule • Conclusion

4/13/2015

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2 SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish


Objective

“The purpose of this paper is to highlight the difficulties faced along with the respective solutions designed and executed during the zonal isolation of a highly permeable, naturally fractured and acidized carbonate reservoir after having performed an extended pressure buildup test on the lowest most cased hole zone”

4/13/2015

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SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish 3


Oil & Gas Exploration

During an exploratory phase, hydrocarbon-bearing rocks are identified. Exploratory wells are drilled, which are later tested to yield the following information:

• Average reservoir rock permeability to the produced phase (oil, gas, or water), within the radius of investigation.

• Skin factor, to quantify damage in the well.

• Average reservoir pressure in the drainage area of the tested well.

• Verification of flow barriers (such as faults) and estimates of distance to these barriers.

• Pressure-Volume-Temperature (PVT) characteristics of the downhole hydrocarbon samples

• Electric logs and productivity data of the formation

“To determine the economic feasibility for a hydrocarbon basin future development”

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http://www.google.com/url?sa=i&rct=j&q=&esrc=s&source=images&cd=&cad=rja&uact=8&ved=0CAcQjRw&url=http://www.jobinoilandgas.com/category/drilling-company/&ei=mYkqVYSLHcX2sAW-mYH4Cg&bvm=bv.90491159,d.b2w&psig=AFQjCNEjvDuqWahelOem9Kg_NrbcZ2GhiQ&ust=1428937477669280


Drilling & Workover Challenge

Challenge

• Any type of isolation requires some means of chemical (cement, polymer, etc.) and/or mechanical (plugs) barriers inside the wellbore.

• The most common type of multi zone completion for testing an exploratory well uses a wireline-deployed plug with cement

• Because of the uncertainty associated with an unexplored reservoir in a newly drilled basin, the optimum differential pressure that an isolation medium would experience in the wellbore is difficult to calculate.

Solution

• Isolate the lower-most zone with a CT-deployed HPHT cement plug and the upper two zones with wireline-deployed plugs with cement.

• The objective of placing a cement plug in the wellbore was the following: – Permanently protect lower

perforations of CH No. 1 from frack conducted on upper zone CH No. 2

– Provide effective isolation of zone CH No.1 for later high-rate matrix stimulation and/or acid fracturing treatment on the upper zone CH No. 2

4/13/2015 SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish

5

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Well X Data

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Test # Reservoir Interval Comments

CH Test # 1 (7” Liner)

LFDR (carbonate)

11,075’ – 11,175’

(100’)

• Complete the well with 7” packer for rig less testing and ensure the downhole completion is able to meet the expected ~12,000 psi to be applied across the perforations during acid stimulation job.

• Perforate CH Test #1, 2 or 3 with 2 7/8” 6 SPF 60deg phasing • RIH downhole gauges 50’ below perforation • RU Coiled Tubing & perform High Rate Acid Matrix Treatment or Bull

head fracture treatment • Flow the well (N2 lift if required), Test and Evaluate • Set downhole shut-in tool and gauge • Perform main flow (N2 lift if required) & final build-up • Retrieve gauges and data • Isolate The zone of interest • Proceed with CH Test #2 or 3

CH Test # 2 (7”Liner)

HANIFA (carbonate)

10,710’ – 10,762’

(52’)

CH Test # 3 (9 5/8” Casing &

7”Liner)

ARAB-D (carbonate)

9,700’ – 9,755’

(55’)

Name From

(ft. MD)

To

(ft. MD)

ID

(in)

Drift

(in)

Burst

(psi)

Collapse

(psi)

Capacity

(bbl./ft.) Remarks

9 5/8”, 53.5#,NKAC-95ST, NK 35B ±0 10100 8.535 8.500 9410 8950 0.07073 TCA tested to 6500

Psi with 53 pcf diesel

7”, 32#, VM-95 HCS, VAM TOP HC 9069 11500 6.094 6.0 10,760 11,160 0.03607 TCA tested to 6500

Psi with 53 pcf diesel 4-1/2”, 13.5#, VM-95 HCS,VAM

TOP HC, Tubing upper Completion ±0 ±9404 3.920 3.795 10,710 11,090 0.01492

Tubing tested to 8000 Psi with 53 pcf diesel

SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish

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Planned Execution

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QDQD-1 (ST-81)

7" 32# 0.03607 bbl/ft

Cement needed 6 bbl

Cement Height 179 Ft

9375.7

9496 TOC

389.3

9675 TTBP

9700

9765

10030 TOC

945

10210 TTBP

10710

10762

1092 TOC

313

11075

11175

11297 PBTD

CH Test #1 LFDR

ARAB-D Isolation TTBP

with CT-Cement

CH Test #3 ARAB-D

CH Test #2 HANIFA


CH No. 3 - Well bore Displacement - Target Zone Perforation - Acid Fracture Treatment - Natural Well Flow back - DHSIT & GH Placement for PBU - Zonal Isolation with CT Cement Plug

CH No. 2 - Well bore Displacement - Target Zone Perforation - Acid Fracture Treatment - Natural Well Flow back - DHSIT & GH Placement for PBU - Zonal Isolation with WL MTTBP & Cement

CH No. 1 - Well bore Displacement - Target Zone Perforation - Acid Stimulation Treatment - Natural Well Flow back - DHSIT & GH Placement for PBU - Zonal Isolation with WL MTTBP & Cement


Design Considerations

• Wellbore Temperature Profile for CT

– Circulating temperatures in CT operations are usually higher than those in conventional squeezes because fluid is pumped at a lower flow rate.

– 1°F/1,000 ft of CT

• Wireline Logs – Production or injection logs for

perforation evaluation help characterize the nature of the contribution or injection from all intervals.

– A pump-in survey with a temperature log can help determine the existence and direction of a channel.

– A pulsed-neutron log with borax brine water injected into the perforations helps define the extent of a channel in the cemented annulus.

– A downhole video camera or casing-caliper log can be used in areas where severe corrosion or erosion is suspected in an older wellbore.


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• Injectivity Test

– Field experience suggests that the minimum surface injectivity for CT cement slurry squeezes should be approximately 1 bbl/min

– A surface injectivity rate greater than 3 bbl/min at low pressures could indicate the presence of high-permeability flow paths, such as fractures, vugs, channels, etc.

• Cross linked Fluid with LCM

– To help prevent these losses, a cross linked fluid with a proprietary LCM product was placed ahead of the cement .

– The gelation time depends on the salinity, pH, temperature, cross linker, and retarder concentration. Extensive laboratory tests are required based on wellbore conditions to fine-tune a slurry recipe


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• Cement Testing Typical testing can include the following:

– Density – Thickening time – Fluid loss – Rheology – Free water and settling – Compatibility – Compressive strength

Job-specific information required for formulating customized test schedules includes:

– Well Downhole Temperature & Pressure

– Mixing Equipment & Procedure – Pump Rate & Placement Time

• Cement Volume for Plug The following factors affect the cement volume:

– Extent and volume of the channeling – Void space behind the pipe left by

produced sand (production history and logs).

– History of lost circulation and openhole calipers (drilling and logging records).

– Displacement efficiency of the primary cement job (cementing and mud reports).

– Size, extent, and number of naturally occurring or induced fractures (drilling and reservoir information).

– Wellbore geometry and tubular dimensions (completion details).

– Differential pressure to be experienced by the plug.

4/13/2015 10 SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish

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Best Practices

• CT and Treating Line Volume

A surface wiper pig was drifted through the entire CT tubing length.

A pigment die was also planned to be used for treating line volume

• Cement Slurry Contamination

Downhole contamination was minimized by placing a suitable volume of spacer in front & behind the cement slurry.

Cement was placed keeping the nozzle in 50ft of slurry volume

• Depth Control and Correlation

CT was run in hole to tag TD and picked up to remove any residual bend.

• Cement Slurry Mixing, Consistency, and Pumping

Cement slurry mixing water was sent to two different labs for compressive strength and thickening time testing, modifications were made based results

Cement slurry was batch mixed for consists density

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Best Practices

• Cement Placement (Spotting) and Squeeze Technique

To minimize U tube effect back pressure was maintained on the CT-Production Tubing annulus

For exact slurry volume a LCM pill was pumped prior to the slurry

• WOC and Testing the Squeeze Plug

Based on the slurry sample gel strength and thickening time at surface temperature, the well was shut in.

• Cement Plug Evaluation

CT was RIH to tag the TOC and circulate out the spacer from the CT-wellbore annulus. Once the wellbore annulus was displaced with clean fluid, the plug was pressure tested to 6,500 psi surface pressure

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Execution Schedule

4/13/2015

Step Start Depth

(ft)

CT End Depth

(ft)

Speed

(fpm)

WHP

(psi)

Pumping Rate

(bbl/min)

Total

(bbl) Pump Fluid

Fluid Coming

Out of CT Nozzle

1 0 11,292 45 0 1 22 75-lbm/ft3 Kill fluid 75-lbm/ft3 Kill fluid

2 11,292 11,292 0 0 1.5 50 75-lbm/ft3 Kill fluid 75-lbm/ft3 Kill fluid

3 11,292 11,292 0 0 1.5 25 Cross linked gel with LCM 75-lbm/ft3 Kill fluid

11,292 11,292 0 0 1.5 25 75-lbm/ft3 Kill fluid 75-lbm/ft3 Kill fluid

4 11,292 10,599 -41.6 0 1.5 25 75-lbm/ft3 Kill fluid Water-control fluid

5 10,599 0 -45 2,500 1 22 75-lbm/ft3 Kill fluid 75-lbm/ft3 Kill fluid

Table: Cross linked gel with LCM pump schedule.

Step Start Depth

(ft)

CT End Depth

(ft)

Speed

(fpm)

WHP

(psi)

Pumping Rate

(bbl/min)

Total

(bbl) Pump Fluid

Fluid Coming

Out of CT Nozzle

1 0 11,292 45 0 1 22 75-lbm/ft3 Kill fluid 75-lbm/ft3 Kill fluid

2 11,292 11,292 0 2,500 1.5 50 75-lbm/ft3 Kill fluid 75-lbm/ft3 Kill fluid

3

11,292 11,292 0 2,500 1.5 20 90-lbm/ft3 Spacer ahead 75-lbm/ft3 Kill fluid

11,292 11,292 0 2,500 1.5 14 118-lbm/ft3 Cement 75-lbm/ft3 Kill fluid

11,292 11,292 0 2,500 1.5 16 90-lbm/ft3 Spacer behind 75-lbm/ft3 Kill fluid

11,292 11,292 0 2,500 1.5 4 90-lbm/ft3 Spacer behind 90-lbm/ft3 Spacer ahead

11,292 11,292 0 2,500 1.5 16 75-lbm/ft3 Kill fluid 90-lbm/ft3 Spacer ahead

11,292 11,292 0 2,500 1.5 1.6 75-lbm/ft3 Kill fluid 118-lbm/ft3 Cement 4* 11,292 10,953 -41.6 2,500 1.5 12.4 75-lbm/ft3 Kill fluid 118-lbm/ft3 Cement 5 10,953 10,903 -25 1,500 0 0 None None

6 10,903 10,903 0 1,500 1.5 20 75-lbm/ft3 Kill fluid 90-lbm/ft3 Spacer behind

7 10,903 0 -45 1,500 1 22 75-lbm/ft3 Kill fluid 75-lbm/ft3 Kill fluid

*The POOH speed in Step 4 depends on the pumping rate. Table: Cement slurry pump schedule.

SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish

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Conclusion

“The successful combination of CT intervention, chemical technology and the implementation of best practices led to the permanent zonal isolation of a acidized naturally fractured zone. This successful zonal isolation implies that reservoirs with severe fluid losses could either be temporarily or permanently plugged using current available chemical technologies with CT deployment” 4/13/2015

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Saudi Aramco: Public Saudi Aramco: Public

Acknowledgement The author & co authors would like to thank Halliburton and Saudi Aramco management for support during the execution of this job.

4/13/2015 SPE-SAS-138 • Account Representative, Halliburton • Syed Muhammed Danish 15

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2015-ATSE-SPE-SAS-138-Presentation