ingepet 2011_expl 2 jb 57 e
TRANSCRIPT
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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) Abstract In 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 Geology The 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) 2The 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 km2 in 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 under development and exploitation since 1959.
Fig. 1: Geographic location.
Background The 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, add
new 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 of perforations, 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) 3Considering 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 Tubing CT 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. 2 shows a land CT unit working on a well.
Fig. 2: Land CT unit working on a well.
True Fluidic Oscillator The 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 travels through 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 of approximately 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 1 shows 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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VII INGEPET 2011 (EXPL-2-JB-57-E) 5
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 barium sulphate and strontium scale in a horizontal well (offshore) in the Campos basin. On the other hand, it presents three cases of vertical wells in onshore Portiguar basin for removal 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 wells with different reservoir properties as well as the best results evidenced compared to other placement techniques (packer, straddle packer, bullheading) in oil-producing wells (23 to 34 API) for shallow and deep vertical removal of organic deposits and stimulation of the near wellbore.
MEXICO (Ulloa et al. 2008 and De la Fuente et al. 2009). The authors document the benefits obtained when using a TFO for selective placement of processing (solvent + blend of inorganic-organic acid) to remove deposits of paraffin, asphaltene, scale, and in fissured carbonate reservoirs of oil producers (28 to 38 API) and gas in vertical, deviated, deep, and hot (248F) wellbores.
Working Methodology To complete these jobs, two main issues have been analyzed. The first was to obtain information that could identify and develop specific chemical treatments for this problem. The second was the operational analysis, execution, and viability of operations.
Information and Diagnosis Initially, 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)
Nozzle Pressure
(psi) Oscillation Frequency Range
(Hz) 1.25 11.05 0.5 2,000 600 700 1.69 9.80 0.5 2,000 600 700 1.69 9.80 1.0 2,000 400 500 2.12 9.80 1.5 2,000 200 - 300 2.88 9.80 3.0 2,000 300
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VII INGEPET 2011 (EXPL-2-JB-57-E) 6FIELD 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 Design Treatments 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 Sequence All 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 up b. Pull out subsurface unit pump c. Isolate pay zone with plug and packer d. Rig down
4. CT operation. a. Rig up b. Perform acid treatment with TFO c. Rig down
5. Workover operation. a. Rig up b. Recover treatment fluid c. Remove plug and packer d. Run in hole subsurface unit pump e. 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 Sequence In the early stages, the pumping sequence applied was:
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VII INGEPET 2011 (EXPL-2-JB-57-E) 71. 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. 4 from left to right.
Fig. 4: Initial sequence.
Pumping Schedule: Modified Sequence The 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. The distribution 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 Histories During 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 reached values 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 treatment was 6.4 m/day (40.3 BOPD) (Fig. 7).
Packer Packer Packer
Tapn Tapn Tapn
LIMPIEZA DEL CASING CON SOLVENTE FORZAMIENTO DEL SOLVENTE A LA FORMACIN FORZAMIENTO DEL ACIDO A LA FORMACINCasing 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) 9Case 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 of 2.8 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 in November 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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VII INGEPET 2011 (EXPL-2-JB-57-E) 11
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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VII INGEPET 2011 (EXPL-2-JB-57-E) 12Conclusions and Recommendations Results. The best results in oil production have been obtained in AG and B fields, with increases of 30 and 360%. The MC and H fields have not achieved these levels, neither in oil production nor total fluid production.
Studies. There is a need for further in-detail diagnostic studies of the problem. Fluid samples, scales, and production history have been observed. These tasks were performed with the intention of improving the treatment formulation for MC and H fields.
Circulation. It is well-known that, in wells where there was no fluid circulation, the results have not been favorable, indicating that not all areas have been treated in the same way. It is advisable to use a relative permeability modifier (RPM) to achieve a more uniform admission profile.
Pay Zone. Given the significant increases in water production in most of the wells, better productive-level identification with greater potential (more selective) is recommended. Applications. The use of a CT unit together with the TFO tool and the treatment selection have proved to be a successful alternative to achieve significant increases in production wells with low profitability.
Acknowledgements The authors thank the management of Pan American Energy and Halliburton for allowing the publication of this work, as well as the field staff of both companies who collaborated in the execution of the work.
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