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    VII INGEPET 2011 (EXPL-2-JB-57-E)

    Stimulation with Coiled Tubing and Fluidic Oscillation: Applications in Wells with

    Low Production (Marginal Profitability) in San Jorge Gulf Area, Argentina:

    Case History

    Juan Bonapace (Halliburton), German Rimondi (Halliburton), Mario Bustamante (Pan

    American Energy), and Rodrigo Quintavalla (Pan American Energy)

    AbstractIn the area of Cerro Dragon (San Jorge Gulf basin (SJGB), Argentina), a group of wells in

    different fields have shown a marked decrease in production in recent years, many of them are

    affected by the secondary recovery system (waterflooding).

    The causes of damage detected in these wells are principally deposits of paraffin, asphaltene,

    and scales (calcium carbonate), the latter caused by the fouling tendency found in water

    samples.

    To increase the production of these wells, workover interventions have been frequently

    conducted by hydraulic fracturing, acid treatments, and reperforating zones. Acid treatments(near-wellbore cleanout) with a CT unit and a new tool called a true fluidic oscillator (TFO) have

    been proposed to find a more cost-effective alternative.

    To enhance the effect of the stimulation systems, the TFO generates a frequency of impact of

    300 to 600 Hz on the formation that weakens and efficiently removes the damage. The CT

    synergy, generation of fluid waves, and the selection systems for optimal acid flow through each

    hole have led to significant results of reduced cost and time and improved production.

    A total of twenty jobs have been performed, 75% of them showed increases in the total fluid

    production; the oil production increased from 30 to 365%. This paper discusses the expertise,

    results, and lessons learned in these fields.

    IntroductionReservoir GeologyThe SJGB is located within the provinces of Chubut and Santa Cruz in southern Argentina. It

    has an irregular shape with greater east-west elongation, having its main development in the

    onshore part (65%) and the rest in the offshore area. Its genesis is of an extensional type in the

    Mesozoic age; the main filling occurred in a stage of rifting from the late Jurassic to early

    Cretaceous period, and the nature of the sediments is predominantly lakes and rivers.

    This basin presents a two-dominant structural style; in the eastern sector, it is extensional and,in the western sector, it is compressional (San Bernardo fold belt). The hydrocarbon traps are

    mostly combined (sedimentary and structural).

    The main production levels are formations, such as Mina del Carmen (formed by a continental

    environment composed of lakes and rivers with light oil), Comodoro Rivadavia, and El Trebol

    (fluvial continental environment of a deltaic type). Sand bodies have thicknesses of 2 to 10 m,

    with porosities varying from 17 to 27%, decreasing in depth, and permeability values fluctuate.

    In general, permeability values average 50 mD.

    Geographic Description

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 2

    The Cerro Dragon area is located 85 km, west of the city of Comodoro Rivadavia, on the

    western flank of the SJGB in the province of Chubut, Argentina (Fig. 1).

    The area operated by Pan American Energy LLC consists of approximately 50 different

    operational fields covering an area of nearly 3500 km2in which 3,800 active wells are located,

    with an average depth of 2200 meters. Half the oil production comes from 60 secondary-

    recovery projects with a total of 650 injection wells. The Cerro Dragon field has been underdevelopment and exploitation since 1959.

    Fig. 1: Geographic location.

    BackgroundThe study area comprises four fields: AG, MC, l H, and B.

    An average well in these fields experiences the following stages:

    Completioninitial period of production in the life of a well (perforations, stimulations).

    Workover interventions with different purposesisolate water production zones, addnew productive levels, or stimulate and restimulate.

    Secondary recoverymaintaining or increasing production through different techniques.

    Throughout the productive life of a well, production decline can be caused by obstruction ofperforations, scaling generation, fine-sediment production, deposition of organic material

    (asphaltene and paraffin), and water blocking.

    To sustain production over time, several alternatives have been applied to maintain or increase

    oil production (acidification, new perforation, and hydraulic fracture) and decrease water

    production (isolated levels, cementing treatments, sealing zones with conformance treatments,

    and mechanical methods).

    Re-perforating to bypass problem zones or zones with decreased production is a common, low-

    cost practice to stabilize or increase production in this field. The results have been favorable in

    most cases.

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 3

    Considering the background and characteristics of the reservoir type (multi-layer) as well as the

    low availability of workover equipment, a technical and economical alternative to conventional

    chemical cleaning (near-wellbore stimulation) is a method of using coiled tubing (CT) with a

    TFO tool.

    Technical DescriptionCoiled TubingCT technology has evolved significantly since the early 1960s, when the first CT unit was built

    and used in the oilfield. As technology improved, CT began to be recognized as a reliable, cost-

    effective, and fast way to perform live-well intervention. A significant breakthrough in CT

    reliability took place in the 1970s and 1980s, when continuous milling came about and

    manufacturing quality was improved. Before this time, CT was manufactured in 1,500-ft sections

    and welded together. Higher-strength steels began to be used to manufacture tubing, adding

    additional durability and strength to the system. Now, CT can be manufactured from steels with

    various high yield strengths, and in sizes up to 4.5-in. OD. Fig. 2shows a land CT unit working

    on a well.

    Fig. 2: Land CT unit working on a well.

    True Fluidic OscillatorThe TFO tool creates pulsating pressure waves within the wellbore and formation fluids. These

    pressure waves help to break up near-wellbore damage and to restore the permeability of the

    formation by carrying a treatment fluid into the formation (Webb et al. 2006). The tool does not

    require a packer and does not contain elastomer sealing elements, which reduces the number

    of elements that can fail. The treatment fluid is then pumped through the tool, into the borehole

    and the formation (Fig. 3).

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 4

    Fig. 3: Fluidic oscillator.

    As fluid flows inside the tool, oscillating pressure waves are created by the Coanda effect,

    discovered in 1930 by Henry Coanda. He observed that a fluid that emerges from a nozzle

    tends to flow near the surface, provided that the curvature is not too accentuated.

    Inside the tool, a fluid stream is repeatedly switched from one passageway to another by means

    of this effect, rapidly oscillating between two different paths. This allows the tool to create

    pressure waves without moving parts and without relying on cavitations. These waves are not

    affected by standoff, as with conventional jetting or velocity tools. The kinetic energy travelsthrough fluid with little energy loss.

    When the wave reaches the formation, the energy is dumped and damage removal is initiated.

    As the damage is removed, the pressure waves are able to penetrate more deeply into the

    formation, removing perforation-tunnel damage, scales, formation fines, mud and cement

    damage, drilling damage, water and gas blocks, and asphaltene/paraffin deposits. The acoustic

    streaming induced by the oscillator focuses the treatment on the immediate area of the tool. The

    action of the chemical is enhanced by the increased contact area with the formation.

    TFOs are available in sizes varying from 1.69- to 2.88-in. OD. This tool is adaptable to both

    jointed pipe and CT applications. The tools operate at an optimal pressure drop ofapproximately 2,000 psi and oscillate at a frequency between 200 to 600 Hz. The tools have

    been used up to 400F, and they are suitable for ga s service. Table 1shows the available tool

    sizes, optimal rates, nozzle pressures, and frequency ranges, and the TFO used in this case

    history is indicated below.

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    Table 1: Available fluidic oscillator data.

    The TFO has been used successfully in several applications, such as (1) removal of damage

    (scale build-up) in gravel-pack screen (Harthy et al. 2004), (2) horizontal wells with poor

    communication (McCulloch et al. 2003), and (3) in cases for general acidification (Gunarto et al.

    2004). Below is a brief summary of different experiences documented mainly in Latin America:

    BRAZIL (Almeida et al. 2009). The author documents a case of removal of bariumsulphate and strontium scale in a horizontal well (offshore) in the Campos basin. On theother hand, it presents three cases of vertical wells in onshore Portiguar basin forremoval of paraffin and asphaltene. In the same production, increases were achieved

    from 20 to 240%, using the low-cost alternative of TFO with joint tubing. COLOMBIA (Gonzalez et al. 2009). The author documents production increases

    achieved by selectively positioning the treatments on multiple levels of production wellswith different reservoir properties as well as the best results evidenced compared toother placement techniques (packer, straddle packer, bullheading) in oil-producing wells(23 to 34 API) for shallow and deep vertical removal of organic deposits and stimulationof the near wellbore.

    MEXICO (Ulloa et al. 2008 and De la Fuente et al. 2009). The authors document thebenefits obtained when using a TFO for selective placement of processing (solvent +blend of inorganic-organic acid) to remove deposits of paraffin, asphaltene, scale, and infissured carbonate reservoirs of oil producers (28 to 38 API) and gas in vertical,deviated, deep, and hot (248F) wellbores.

    Working MethodologyTo complete these jobs, two main issues have been analyzed. The first was to obtaininformation that could identify and develop specific chemical treatments for this problem. Thesecond was the operational analysis, execution, and viability of operations.

    Information and DiagnosisInitially, samples were taken from deposits (scales) in production lines. These were analyzed to

    determine the type of scale. In addition, the different chemical treatments were tested for

    suitability. These results suggested a formulation of hydrochloric acid (HCl) would have a

    greater power of dissolution.

    Later, because of the difficulty associated with obtaining representative samples of the

    subsequent wells, this formulation was adopted as the basis for the treatment. Furthermore, to

    check on the initial formulation and improve it, said treatment was evaluated using the

    information derived from water tests, fouling tendency (carbonates, sulphates), and composition

    of oil (paraffin, asphaltene). A summary of the main characteristics of these points for each

    deposit is described in Table 2.

    Tool OD(in.)

    Length(in.)

    Optimal Flow Rate(Bbl/min)

    NozzlePressure

    (psi)

    Oscillation Frequency Range(Hz)

    1.25 11.05 0.5 2,000 600 7001.69 9.80 0.5 2,000 600 7001.69 9.80 1.0 2,000 400 5002.12 9.80 1.5 2,000 200 - 3002.88 9.80 3.0 2,000 300

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 6

    FIELD AG MC H B

    Scale (tendency) low - moderate very low very low without

    % Paraffin 9 8 9 > 10

    % Asphaltene 4 4 8 3

    Table 2: Analysis performed.

    The analysis obtained has allowed identification of the type of damage, such as organic (wax

    and asphaltene) and inorganic deposits (calcium carbonate) located near the well (near-

    wellbore skin).

    Treatment DesignTreatments have been designed as near-wellbore stimulation to be pumped to a matrix system

    using a volume ratio between 25 and 50 gal/ft perforated (an average of 30 gal/ft perforated was

    used); thus, yielding a radius of penetration of about 2 to 3 ft seeking to reduce the positive skin.

    The laboratory results on samples of scale indicated a base solution formulated with 10% HCl

    and 5% mutual solvent. Additionally, this treatment was supplemented with corrosion inhibitor,

    surfactant, clay stabilizer, penetrating agent, and iron sequestering and aromatic solvent at an

    early stage. Later, to optimize the treatment, certain components were modified, such as pH

    controller, a paraffin inhibitor, solvents, emulsifier, and micro-emulsion.

    Operation SequenceAll the work conducted has had the same sequence of development in the preparation of the

    well and subsequent execution of the production stage detailed below:

    1. Stop well in production.2. Rig down and remove surface unit pump.3. Workover operation.

    a. Rig upb. Pull out subsurface unit pumpc. Isolate pay zone with plug and packerd. Rig down

    4. CT operation.a. Rig upb. Perform acid treatment with TFOc. Rig down

    5. Workover operation.a. Rig upb. Recover treatment fluidc. Remove plug and packerd. Run in hole subsurface unit pumpe. Rig down

    6. Rig up surface unit pump.7. Put well back into production.

    The appropriate and necessary logistics to help minimize the nonproductive times, benefiting

    the economy of the well and the project, were implemented.

    Pumping Schedule: Initial SequenceIn the early stages, the pumping sequence applied was:

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 7

    1. Because the bottomhole assembly (BHA) was at the bottom of the chamber (area

    between the plug and the packer), the proceeding consisted of washing this surface with

    linear gel treated water.

    2. While the BHA remained at the bottom, the pumping treatment was initiated (acid and

    solvent).

    3. The chamber was filled with treatment fluid.

    4. The CT was raised to the packer.5. The well was closed (annulus-closed) and a rundown was performed to the bottom of

    the well, forcing the treatment into the formation.

    6. The annulus was opened to recover as much of the surface treatment as possible, as

    well as the waste material that could have remained from the chemical action.

    This initial sequence of applying the treatment was carried out in the first eight operated wells

    (AG). The sequence described above is shown in Fig. 4from left to right.

    Fig. 4: Initial sequence.

    Pumping Schedule: Modified SequenceThe treatment placement was analyzed to improve its efficiency. This resulted in dividing the

    treatment into two stages, the first one consisting of solvent, and the second one of acid

    treatment.The objective was to improve the solubilization of inorganic compounds with acid

    treatment. To achieve this, the solvent was pumped during the first stage, so that organic

    compounds could be removed

    The new pumping sequence used was:

    1. The chamber was cleaned (casing cleaning) with a solvent-based treatment.

    2. The chamber was washed to remove any debris generated by this first solution.

    3. Once the annulus was closed, solvent was injected to the formation to clean the near-wellbore area.

    4. In the second part of the treatment, a volume of acid solution was injected.5. In the last stage of the sequence, the annulus was opened to recover the greatest

    amount of fluid pumped (wasted acid), circulating with the CT in the downhole.

    This method of applying the treatment has been used on wells AG, MC, H, and B. Thedistribution mechanism is shown in Fig. 5.

    2480 ft 2480 ft

    2980 ft 2980 ft

    CERRAR

    RETORNO

    ABRIR

    RETORNO

    Closed

    annulus

    Open

    annulus

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 8

    Fig. 5: Modified sequence.

    Case HistoriesDuring the period from 2007 to 2009, 20 jobs in these fields were completed, showing increases

    in oil production of 60% and also an increase in the total fluid produced (i.e., water + oil) in 75%

    of the operated wells. Six representative cases of these fields appear below.

    Case 1 (PXAG-5)

    The well geometry consisted of 7-in., 20-lb/ft production casing and 2 7/8-in., 6.4 lb/ft production

    tubing. The area of interest covered four levels of production (from 2,589 to 2,956 ft) with a total

    of 26.5 ft of perforation placed in a 403.5-ft chamber (distance between plug and packer). Two

    treatments were performed on this well. The first was in November 2007 using the initial

    pumping sequence, and the second, in July 2009, was applied with the modified pumping

    sequence. The average oil production for the first half of 2007 was 3.3 m/day (20.8 BOPD). A

    sudden, sharp drop between July and September, with production dropping to 2 m/day (12.5

    BOPD), was the reason for the first completion treatment performed. The resulting production

    was 6.9 m/day (43.4 BOPD); an increase of 245%. In June 2009, there was a similar drop in

    production to 2.2 m/day (13.8 BOPD). After repeating the treatment, the production reachedvalues of 4.9 m/day (30.8 BOPD); an increase of 122% (Fig. 6).

    Case 2 (PXAG-801)

    The well geometry consisted of 5 -in., 15.5-lb/ft production casing and 2 7/8-in., 6.4-lb/ft

    production tubing. The area of interest covered six levels of production (from 2,493 to 2,973 ft)

    with a total number of 54 ft of perforation placed in a 525-ft chamber. A treatment was

    performed on this well in October 2007 following the initial pumping sequence. The average oil

    production before the treatment was 1.8 m/day (11.3 BOPD). After the treatment was

    performed and the injected dose recovered, the well production was 8.3 m/day (52.2 BOPD);

    an increase of 360%. In the two years following, the average oil production after the treatmentwas 6.4 m/day (40.3 BOPD) (Fig. 7).

    Packer Packer Packer

    Tapn Tapn Tapn

    LI MPI EZA DEL CASI NG CON SOLVENTE FORZAMIENTO DEL SOLVENTE A LA FORMACIN FORZAMIENTO DEL ACI DO A LA FORMACIN

    Casing cleaning with

    solvent

    Solvent Injection into

    formation

    Acid Injection into formation

    Packer

    Plug

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 9

    Case 3 (PXB-858)

    The well geometry consisted of 5 -in., 15.5-lb/ft production casing and 2 7/8-in., 6.4-lb/ft

    production tubing. The area of interest covered seven levels of production (from 2,447 to 3,032

    ft) with a total of 49 ft of perforation placed in a 627-ft chamber. This well was treated in

    November 2008 following the modified pumping sequence. The average oil production in 2008

    was 2.1 m/day (13.2 BOPD). After treatment in 2009, production increased to an average of2.8 m/day (17.6 BOPD). This value represents a constant increase of 33% (Fig. 8).

    Case 4 (PXAG-827)

    The well geometry consisted of 5 -in., 15.5-lb/ft production casing and 2 7/8-in., 6.4-lb/ft

    production tubing. The area of interest covered seven levels of production (from 3,534.5 to

    4,483.5 ft) with a total number of 76 ft of perforation placed in a 984-ft chamber. In October

    2008, a treatment was performed following the initial pumping sequence. The average oil

    production for the first half of 2008 was 2.1 m/day (13.2 BOPD). After performing the treatment

    and for a further period of one year, the average oil production was 1.2 m/day (7.5 BOPD). This

    did not result in improved oil production, although water production increased from 1.1 m/day(6.9 BWPD) to 9.1 m/day (57.2 BWPD) in the same period of time; an increase of 720% (Fig.

    9). For future stimulation treatments, the use of water-control systems (i.e. relative permeability

    modifiers) will be considered in the treatment schedule to help minimize water production in

    these marginal wells. This methodology has proved successful in other parts of the world

    (Garcia et al. 2008).

    Case 5 (PXMC-848)

    The well geometry consisted of 5 -in., 15.5-lb/ft production casing and 2 7/8-in., 6.4-lb/ft

    production tubing. The area of interest covered seven levels of production (from 6,713 to 7,015

    ft) with a total of 64 ft of perforation placed in a 374-ft chamber. This well was treated inNovember 2008, following the modified pumping sequence. The average oil production in 2008

    was 1.2 m/day (3.9 BOPD) before the treatment. The average oil production for the 12 months

    following treatment was 0.6 m/day (1.96 BOPD), which indicated no meaningful improvement.

    Nevertheless, a slight increase was evidenced in water production; from 20.1 m/day (65.9

    BWPD) before treatment to 22.1 m/day (72.5 BWPD) for the same period of time; an increase

    of 10% (Fig. 10).

    Case 6 (PXH-841)

    The well geometry consisted of 5 -in., 15.5-lb/ft production casing and 2 7/8-in., 6.4-lb/ft

    production tubing. The area of interest included five levels of production (from 2,743 to 3,414 ft)

    with a total of 45 ft of perforation placed in a 722-ft chamber. A treatment was performed on this

    well in October 2008 using a modified pumping sequence. The average oil production for 2008

    was of 7.2 m/day (45.3 BOPD). After the treatment was performed and the injected dose

    recovered, the well had an average oil production of 4.2 m/day (26.4 BOPD) for one year. No

    significant improvement was observed. Nevertheless, a slight increase in water production from

    15.5 m/day (97.5 BWPD) to 16.4 m/day (103.1 BWPD) during the same period of time,

    representing an increase by 6% (Fig. 11).

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 10

    Fig. 6: Well PXAG-5 production history.

    Fig. 7: Well PXAG-801 production history.

    Fig. 8: Well PXB-858 production history.

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    Productio

    n(m3/day)

    Well: PXAG-5

    OIL TOTAL WATER

    Treatment 5-Nov-07Treatment 5-Jul-09

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    Fig. 9: Well PXAG-827 production history.

    Fig. 10: Well PXMC-848 production history.

    Fig. 11: Well PXH-841 production history.

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    OIL TOTAL WATER

    Treatment 9-Jul-08

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    OIL TOTAL WATER

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    VII INGEPET 2011 (EXPL-2-JB-57-E) 13

    McCulloch, D., Mann, J., Macmillan, P., and Ali, S. 2003. Damage Removal in Screened

    Horizontal Wells. Paper SPE 81732 presented at the SPE/ICoTA Coiled Tubing Conference,

    Houston, Texas, USA, 89 April. doi: 10.2118/81732-MS.

    Ulloa Gutierrez, J.V., Franco Callarotti, G. Akrich, O., and Rodriguez Monroy, R. 2008.

    Stimulation with Coiled Tubing and Fluidic Oscillation. Paper SPE 113716 presented at the

    SPE/ICoTA Coiled Tubing and Well Intervention Conference and Exhibition, The Woodlands,Texas, USA, 12 April. doi: 10.2118/113716-MS.

    Webb, E., Schultz, R., Howard, R., and Tucker, J. 2006. Next Generation Fluidic Oscillator.

    Paper SPE 99855 presented at the SPE/ICoTA Coiled Tubing and Well Intervention Conference

    and Exhibition, The Woodlands, Texas, USA, 45 April. doi: 10.2118/99855-MS.