Cementing, Perforating, And Fracturing Using Coiled Tubing_Peru (1)

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SPE 138798

Cementing, Perforating and Fracturing Using Coiled Tubing: RiglessCompletion Technique Developed for a Marginal Field in PeruV. Salazar, BJ Services; V. de la Rosa, Sapet Develpment;and J. Gomez and J. Quintana, BJ Services

Copyright 2010, Society of Petroleum Engineers

This paper was prepared for presentation at the SPE Latin American & Caribbean Petroleum Engineering Conference held in Lima, Peru, 13 December 2010.

This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewedby the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, ormembers. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print isrestricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright.

Abst ractThe Talara field, onshore Peru, is one of the oldest oilfields in the world. It was discovered in late 19th century and up to 2010

more than 12,000 wells have been drilled. Currently, only some 3,000 wells are active; the remaining ones have been temporarily

or permanently abandoned due to low production.

Recently, a new pay zone was found above the typical producing formation in this field. However, two factors complicate any

plans to recomplete the old wells and produce from the new formation. In first place, in the typical well configuration, theproduction casing in these wells is not cemented to surface and the cement top is below the new zone. Secondly, because the new

pay zone is in a low-permeability formation, it must be fractured to be commercially produced. A conventional rig-based workoverto recomplete and fracture this upper payzone is too expensive to be economically viable.

This paper presents a new rig less completion technique involving plug and abandonment of the lower zones, followed by

cementing, perforating and fracture stimulating the new zone using only coiled tubing for intervention. The technique has proven

to be an economically viable way to bring back to life the first 18 wells completed.

Operational details, production results and lessons learned from this first campaign are presented. The analysis demonstrates thatthis new system can reduce completion time and costs in open-hole wells for both mature and new fields.

IntroductionThe Talara basin, in the northeast Peruvian coast, holds several very mature fields producing from low permeability, very complex

sandstones. The original target zones were located at more than 4,000 ft in Parias, Mogollon and Basal Salina formations.

Presently, in most of the blocks, these original targets are very depleted and well interventions are usually bellow the economical

limit. For this reason, other reservoir formations which were not considered as viable targets are now being considered interestingfor recompletion. In this analysis there upper formations considered were: Verdun, Helico and Talara. They hold oil reserves able

to be produced. However, in blocks 6 and 7 of the Talara Basin, the wells have gone by this formation, most of them having being

drilled in the 1940s, were cemented with the cement top bellow these formations. Considering the reservoir conditions of low

permeability and low pressure, the wells need to be hydrualically fractured to be produced.

Since these wells do not have hydraulic isolation to surface from the formations to be recompleted, the challenge is to be able toprovide cement isolation to the reservoirs in order to complete with hydraulic fracturing. The fields are very mature and the

expected production is quite low, thus this recompletion process could eventually be beyond the economical limit, thus thechallenge is that this recompletion has to be deployed at the minimum possible cost. If successful, hundreds of opportunities will

be available for this type of recompletion. This paper is based mainly on experience in Talara. The approach used to achieve this

objective was to perforate, deploy cement isolation and fracture stimulate in a simple rigless operation, with the minimum amount

of equipment and people.


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Recompletion OverviewAfter analyzing different options, the selected approach was to use a light coiled tubing unit to perforate and to deploy cement

isolation rings above and below the fracturing zone. Then, to perforate and fracture the Verdun formation. This procedure to beperformed in one or several stages if required, depending the thickness of the reservoir. The perforations were achieved using the

sand jet technique. Since it has been impossible to circulate though the non cemented section, the cement isolation was placed by

squeezing cement through the perforations.

The process is better described in the following drawings:

Step 1: Set a bridge plug or a gel plugStep 2: Sand jet perforation of the lower squeeze interval

Step 3: Squeeze cement

Step 2 Step 3 Step 4Figure 1. Rigless Recompletion in Verdun, steps 1-3

Step 4: Clean the cement in the wellboreStep 5: Sand jet perforation of the upper squeeze interval

Step 6: Squeeze cement

Step 6 Step 8 Step 9

Figure 2. Rigless Recompletion in Verdun, steps 4- 9Step 7: Clean cement


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Step 8: Sand jet perforate the frac interval

Step 9: Hydraulic fracture, clean proppant and install artificial lift.

This procedure resulted in good enough cement isolation to effectively stimulate the target zones. The recompletion wasperformed in shorter time and cost, compared to a rig based operation. Details of each step are shown below:

Sand Jet PerforationThe Sand Jet perforation is a process that uses a high pressure abrasive fluid slurry to perforate the casing and the cement in an oil

or gas well and simultaneously extend a cavity into the reservoir. In order to properly assess the performance of this techniquewith the available equipment and well conditions, regarding perforations penetration, jetting time required, optimum rate and

pressure differential, a yard test was performed.The tool used to cut the perforations was a three nozzle 2 7/8 sand jet tool, with 4 OD centralizers. The 3 jet nozzles used were1/8. The tool was run with a 1 coiled tubing and the perforations were cut with treated water pumped with 1 lb/gal of beach

sand. For this yard test, 6 deep, 15 diameter hole was built. Inside it, a 5 casing was run and cemented. The cement sheath

thickness was 9.0

(A) (B)

Figure 3. Yard Test: (A) Pilot Hole (B) Cement Sheath Thickness

For the test, the sand jetting tool BHA was run inside the 5 casing with a 1 coiled tubing. The typical casing size for the

wells in the area is 5. However, there are also candidates with 4 and 6 5/8 casings. The results were successful. The createdperforation passed the cement sheath after 10 minutes of jetting the sand - fluid slurry. The created tunnel was 11 mm diameter. Itwas clean and debris free, as shown in Figure 4.

(A) Diameter (B) Extension (C) Cemented zone penetration

Figure 4. Yard Test: Perforation tunnels created by Sand Jet Tool


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The number of perforations for the actual operations were designed based on the actual first job observations. For the cement

squeezes: injectivity tests to deploy the cement ring in the annulus. For the fracture operation: the assessed parameter was the

observed perforations friction and near wellbore friction losses (NWBF). They were calculated using step down tests.

Both the test and the operations were

(A) (B)

Figure 5. Sand Jet Perforating plots (A) Pilot well-Surface Tests (B) Typical Well

The operation is typically performed by pumping treated water with 1 pound per gallon (ppa) of sand at 1.35 bpm. Three

perforations (one jetting point) are enough to deploy and squeeze the cement slurry and 45 to 60 perforations (15-20 jetting points)are enough for the fracture stimulation, with less than 100 psi of near wellbore pressure loss. This low perforation friction resulted

in the fact that actual perforation tunnels do not exist, but only casing and open hole behind it. The cutting time followed the 10

minutes per jetting point standard, as per the yard test.

Cement IsolationSince the recompletion target reservoirs are above the cement top, hydraulic isolation is a must in order to fracture stimulate.

Initial approaches to provide hydraulic isolation included casing cut and new casing run, and attempts to circulate cement tosurface. The first resulted in a very expensive workover, and in the second case was unable to circulate fluids behind the casing

usually due to very old mud with solid spots between the casing and the bore hole.

The solution was to perforate and squeeze cement bellow and above the section to be fractured, to create isolation cement rings

behind the casing. Despite the fact that this approach does not guarantee a complete and safe proof isolation, the results observedand fracture treatment pressure behavior demonstrate that it has been successful and the objectives have been fully met. Figure 5

shows the fracturing job pressure behavior. The pressure is above the fracturing pressure and no response in the annulus pressure

was observed.

The cement squeezes consist usually in 10 bbl of 15.6 ppg cement slurry. The slurry is spotted in front of the cut perforations and

then it is heisted several times in order to create the cement ring. Just below the squeezing zone, a sand plug is used in order toavoid cement settling. For the second squeeze, a sand plug is also used; in both cases a gel spacer is used between the sand and the

cement in order to prevent hard cement. After the squeeze, the cement remaining inside the casing is contaminated with gel in

order to be able to circulate it out of the hole after the squeezed cement set. The contamination procedure and the slurry properties

were adjusted after the first jobs where the set cement was found very hard inside the wellbore and a time consuming cement

drilling operation was needed. The cement rings in the annulus were tested with integrity tests at pressure similar to the oneexpected in the fracture treatment. This ensures that the fracture treatment is going to be placed in the target reservoir. Figure 6

shows a plot of the operation parameters of a typical cement squeeze job.

The cement slurry was designed in the laboratory to have low rheology and thickening time enough to reach squeeze pressure and

then to be able to clean the cement excess in the same trip (to avoid a drilling run). See Figure 2, Step 4. Table 1 shows the most

relevant cement slurry properties


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Table 1. Cement Slurry Properties

Figure 6. Typical cement squeeze operation

Fracture StimulationAfter the perforations are cut and when the cement rings have developed a compressive strength of at least 800 psi, the fracture

treatment is performed.Figure 7 shows the parameters of a typical fracturing operation, the treatment parameters plot on the left are from a well worker

under this recompletion technique, the graph on the right is a normal well cemented to surface. The pressure during the treatment

is above the fracturing pressure. No pressure response was observed in the casing to casing annulus.

An analysis comparing previous conventional treatments and the new rigless approach treatments is shown in Figure 7. The

pressure behavior confirms that the fracture gradient and the fracture extension pressure in the minifrac, as well as treating

pressure and net fracture pressure are quite similar in both treatments. This confirms that the zonal isolation was reached and thatthe stimulation was properly placed in the target zone.

Fracture treatments in wells with standard rig completion (and primary cement) showed perforation friction and NWBF between300 a 400 psi, see figure 7 (B). Fracture treatments in wells recompleted with the new rigless CT technique showed a perforation

and NWBF pressure loss between de 0 a 50 psi, see figure 7 (A).

This fact not only reduces the pumping pressure requirements but also results in a better production results from a better fractureand from good communication between the fracture and the well. The low calculated net pressure at the end of the minifracs also

suggests that no multiple fractures are being created, despite the fact that when fracture stimulating an openhole section, there isrisk of creating multiple fractures, thus resulting in a shorter fracture geometry.

(A ) Frac treatment with rigless CT recompletion (B) Frac Treatment with normal primary cementing

Figure 7. Typical fracturing job parameters

Units

Thickening Time 3 to 4 Hr

Filtrate < 50 ml / 30 min

Plastic Viscosity < 100 cPCompressive Strength > 1000 Psi / 12 hr


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Table 2. Rigless CT Fracture Recompletions

Well Recompletion

Time (day)

Stages

1 3 1

2 2.5 1

3 2.4 1

4 1 15 4 2

6 3.5 2

7 2 1

8 2 1

9 2 1

10 2 1

11 2 1

12 2 1

13 2 1

14 2 1

15 2 1

16 2 117 2 1

18 2 1

Conclusions

18 successful operations confirmed that coiled tubing is a successful means to deliver a rigless completion including perforating,

cementing and hydraulic fracturing.

The rigless coiled tubing recompletion process proved to be an effective way to reduce costs, simplify the operation and accessreserves that could probably be not economical if a conventional rig was used.

Sand Jet perforating is a successful mean to cut holes in the casing in order to inject cement to the casing - hole annulus.

Sand Jet perforating is successful technique to create perforation tunnels passing the critical damage area. This results in a better

fracture geometry and provides a more effective communication from the reservoir to the well.

Rigless CT deployed cement rings squeezed through a few perforations. were successful to provide zonal isolation for fracture

stimulation operations.

Acknowledgments

The authors would like to thank the management of Sapet Development and BJ Services for the permission to publish this paper.

Nomenclature

BHA = Bottom Hole Assembly

BPM = Barrels per Minute

CT = Coiled Tubing

NWBF = Near Well Bore Friction Loss

PPG = Pounds per Gallon


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FT = Feet

ID = Internal Diameter

OD = External Diameter

LB = Pounds

PSI = Pounds per Square Inch

SG = Specific Gravity

STP = Surface Treating Pressure

SI Metric Conversion Factors

Bbl 1.589 873 E 01 = m3

cP 1.0* E 03 = Pa . s

Lbm 4.535 E-01 = kg

mD 9.869 233 E 04 = m2

Ft 3.048* E 02 = m

In 2.54* E +012 = mm

Psi 6.894 757 E + 00 = kPa

*Conversions factors are exact

References

1. Daneshi, A., Daneshi Consultants: Factors Controlling Vertical Growth of Hydraulic Fractures, paper SPE 118789 presented at theSPE Hydraulic Fracture Conference held in The Woodlands, Tx, U.S.A., 19-21 January 2009.

2. Schultz, D., BJ Services; Thompson, D., EnCana; and Whitney, D., Thru Tubing Solutions: Abrasive Perforating via Coiled Tubing

Revisited. paper SPE 107050 presented at theSPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, 20-21March 2007, The Woodlands, Texas, U.S.A.

3. Hari, R., SPE, TriAxon Resources, and Laun, L., SPE, BJ Services Company, Canada: Improvements in Multistage Fracturing ofHorizontal Wells Using a Newly Introduced Single Trip Coiled Tubing Conveyed Annular Perforating and Fracturing Tool - Benefits,

Savings, and Case Histories. SPE paper 127738 presented at the IADC/SPE Drilling Conference and Exhibition, 2-4 February 2010,New Orleans, Louisiana, USA

4. Cobbett, J.: Sand Jet Perforating Revisited. Paper SPE 54044 published in the SPE Drilling & Completions Magazine, Volume 14,number 1, in March, 1999.

5. Dotson, T., Farr, J. and Findley, E., TD Tools, Inc: Advances in Sand Jet Perforating. Paper SPE 123569 presented in the SPE RockyMountain Petroleum Technology Conference, 14-16 April 2009, Denver, Colorado

Cementing, Perforating, And Fracturing Using Coiled Tubing_Peru (1)

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