ibp 3411 2010 stimulation of horizontal passive-flow...

______________________________ 1 Petroleum Engineer - Schlumberger, Senior Production Engineer CIROP 2 Ph.D. Petroleum Engineering – Schlumberger, Production Solutions Manager

IBP3411_10 STIMULATION OF HORIZONTAL PASSIVE-FLOW-CONTROL

COMPLETIONS IMPROVE PRODUCTION AND RECOVERY IN

NATURALLY-FRACTURED-CARBONATE RESERVOIRS Juan C. Rodriguez 1, Jose G. Flores 2

Copyright 2010, Instituto Brasileiro de Petróleo, Gás e Biocombustíveis - IBP

Este Trabalho Técnico foi preparado para apresentação na Rio Oil & Gas Expo and Conference 2010, realizada no período de 13 a 16 de setembro de 2010, no Rio de Janeiro. Este Trabalho Técnico foi selecionado para apresentação pelo Comitê Técnico do evento, seguindo as informações contidas na sinopse submetida pelo(s) autor(es). O conteúdo do Trabalho Técnico, como apresentado, não foi revisado pelo IBP. Os organizadores não irão traduzir ou corrigir os textos recebidos. O material conforme, apresentado, não necessariamente reflete as opiniões do Instituto Brasileiro de Petróleo, Gás e Biocombustíveis, seus Associados e Representantes. É de conhecimento e aprovação do(s) autor(es) que este Trabalho Técnico seja publicado nos Anais da Rio Oil & Gas Expo and Conference 2010.

Summary

Acid matrix stimulation is a known enabler to remove formation damage and enhance productivity of horizontal wells drilled in naturally-fractured-carbonate reservoirs. While the stimulation mechanisms and operational processes are well known to the oil industry, little is known about the effect of passive inflow-control devices, installed in the horizontal completion to selectively produce sections of the reservoir at rates depending on their petrophysical properties and fracture densities, over the effectiveness of the acid stimulation job. Moreover, there is no consensus in the industry as what would be the best operational approach to stimulate these wells. Two different operational methodologies for the matrix stimulation of horizontal passive-flow-control completions in naturally-fractured-carbonate reservoirs using conventional acid formulations are discussed in this paper. The first technique consists of placing the treatment as close to the zone of interest as possible using coiled tubing, while the second approach consists of bullheading the treatment from the surface. The analysis and production results, including PLT logs, indicate that a combination of coiled-tubing conveyance and the application of diversion mechanisms improve zone coverage and facilitate the removal of formation damage. It was also found that conventional bullheading is less effective to remove damage. It is concluded that key to successful damage removal in horizontal passive-flow-control completions in carbonate reservoirs is the placement of the treatment via coiled tubing, and the application of suitable diversion mechanisms.

Abstract

The stimulation of horizontal wells to remove induced or production-related formation damage in naturally-fractured-carbonate reservoirs is a challenging problem. Formation damage can be caused by a variety of mechanisms, including emulsions, wettability changes, water blocks, scales, organic deposits, mix of organic and scale deposits, silt and clay, bacterial deposits, or a combination of the above, requiring the proper treating fluids. Reservoir heterogeneities, the length of the horizontal well and the ability to stimulate the low permeability zones, controlling the flow in the high permeability fractures require the implementation of difficult diversion mechanisms. The problem further complicates if the well is fitted with passive inflow-control devices. There is little experience in the industry, and none in the published literature on the matrix stimulation of horizontal passive-flow-control completions in carbonate reservoirs, requiring operators to carry out trial tests to determine the stimulation methodologies and procedures suitable to their needs.

This paper presents a systematic operational approach to the acid matrix stimulation of horizontal passive-flow-control completions in naturally-fractured-carbonate reservoirs. Two operational methodologies will be revisited, including (1) placing the stimulation treatment as close to the zone of interest as possible with the assistance of coiled tubing and, (2) bullheading the treatment from the surface; with emphasis on the use of divergence, specifically foams of various qualities. The laboratory studies, modeling and development of the field procedures are described, and case studies are presented, including sample evaluation logs run before and after the stimulation job for both, bullheading and coiled tubing placement techniques.

1. Introduction

Naturally-fractured-carbonate formations tend to be extremely heterogeneous, with complex porosity and

Rio Oil & Gas Expo and Conference 2010

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permeability variations, barriers and irregular flow paths. A major problem faced during the development of highly-prolific, naturally-fractured-carbonate reservoirs is the reduction of the oil window in the reservoir, as a result of the dynamics imposed by the depletion process. As the oil is produced and the fields mature, the displacement of the Gas-Oil Contact (GOC) and the Oil-Water Contact (OWC) narrow down the oil column available for exploitation. One of the most effective alternatives to continue producing oil at high rates, and efficiently manage the reservoir energy is to drill and complete horizontal wells with passive Inflow Control Devices (ICD), to selectively produce sections of the reservoir at rates proportional to their petrophysical properties, fracture densities and relative locations along the wellbore.

Horizontal wells are very effective in exposing the wellbore to maximum reservoir contact and drainage area for recovery economics, which is very crucial in thin oil rims. Horizontal wells can produce with lower pressure drops thus delaying gas and water breakthrough along their length. However, pressure losses due to frictional effect occur along longitudinal flow and imbalance the horizontal flow, resulting in higher drawdowns at the heel of the horizontal well. Consequently, premature water or gas breakthrough occurs at the heel, while minimal oil is produced towards the toe section, causing a large fraction of remaining oil bypassed. This negative impact can be even worse when combined with larger formation permeability contrasts from heel to toe in a heterogeneous media, such as a naturally-fractured-carbonate reservoir. To address this problem, the completion is fitted with passive ICD’s proved to normalize non-uniform flow. In these installations, a highly productive zone near the heel or across high permeability streaks is normalized or even suppressed, while the lower pressure regions or less productive zones are accelerated with higher drawdowns provided by the ICD’s to create an overall balanced influx from toe to heel (Raffn et al. 2008). Figure 1 shows schematically the configuration of a typical ICD device, its location in a horizontal completion, and how an ICD installation can help produce a more uniform sweep of the fluids in the reservoir.

Figure 1. Details of an ICD and schematic of its location in a typical horizontal completion

Despite the recent technical advances in the placement and completion of horizontal wells, many new wells drilled in naturally-fractured carbonates still exhibit low productivities, essentially because of significant mud losses while drilling the reservoir sections. It is often the case that mud solids and fines plug the natural fractures, also forming a cake that seals the low-permeability matrix, essential component for the continuous production of the reserves. Another frequently-observed formation damage mechanism consists of emulsions, formed deep inside the reservoir by the water-based polymeric mud reacting with the native fluids, curtailing productivity.

The stimulation of carbonate rocks involves the reaction of an acid with the rock minerals to create intricate, high-permeability channels or wormholes, and to remove formation damage in the near-wellbore area. The key to successful skin remediation is ensuring that live acid contacts the complete productive interval and is distributed fairly evenly across the zone (Chesson et al. 2008). Mechanical and chemical means, including Nitrogen foams, wax beads, benzoic acid flakes, gelled polymers and other more elaborate systems are generally used to divert acid at the wellbore away from high permeability fractures to treat low permeability matrix.

2. Stimulation Placement Strategies

Conventional stimulation treatments today use regular HCl or retarded acids in conjunction with chemical diverters to remove formation damage in horizontal wells drilled in carbonate formations. Carbonate reservoirs can be


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extremely heterogeneous, and therefore the reservoir zones within a long horizontal well may respond differently to standard stimulation treatments. An effective stimulation program would treat each zone appropriately, matching the needs of the interval to the most suitable stimulation methodology (Schlumberger 2007). Coiled tubing (CT) is a well-established conveyance technique for delivering stimulation fluids in horizontal wells; however, in long horizontal wells or under certain well configurations, the CT stimulation method may not be feasible. In the absence of a CT-based delivery mechanism, some operators have no other option but to bullhead the acid by pumping it from the surface at high rates. In the case of conventional horizontal completions, CT has proved to be effective for placing the acid and to obtain the maximum coverage (Saxon et al. 2000; Safwat et al. 2002; Chesson et al. 2008), and generally, CT is regarded as more effective than bullheading when evaluated in terms of delivering production results (Thomas and Milne 1995; Mitchell et al. 2003), as bullheading tends to concentrate the acid in the heel or most permeable section of the well, leaving the remainder of the well untreated.

Effective diversion is the key to the success of matrix stimulation treatments (Nasr-El-Din et al. 2006). Without diversion, acid tends to seek the path of least resistance and enters only a small portion of the interval being treated. Chemical diverting agents temporarily block the more permeable zones of the well, forcing the acid into damaged or less permeable zones. In naturally fractured reservoirs, in which the horizontal well crosses zones of large contrast in permeability and damage, diversion is essential in matrix stimulation treatments.

In the conventional case, the placement strategy is fundamentally dictated by the problem to solve and the information available. For example, knowing that a thief zone exists in the middle of the horizontal section (Figure 2), the CT can be run to that depth to inject a diverter slug. The diverter will not completely plug the thief zone but will dramatically decrease the flow of treating fluids into that zone. This process could be repeated as required based on production and fissure-location logs. Subsequently, the CT can be run to total depth to start the main treatment. If insufficient data are available, the entire section is normally treated by alternating acid and diverter stages as the CT is retrieved from total depth; however diversion is essential to ensure that the treating fluid is continuously removing damage rather than simply being injected into a thief zone. For example, Table 1 shows the typical acid and diverter placement techniques applicable for the stimulation of horizontal wells in naturally-fractured-carbonate reservoirs, as a function of the location of a thief or high permeability zone.

High permeabity

(Middle zone)

Zone 2

High permeabity

(Toe- Lower zone)

Zone 3

High permeabity

(Heel-Upper zone)

Zone 1

Coiled

tubing

Coiled tubing

Heel 7” L-80 26#

Inflatable

PackerPICD 4 ½” O H. 6 1/8”

Hanger7”x 4-1/2”

Permanent gauge

3495md3252md

Blank pipe7” 2964md

X m X+130 m X+180m X+320m X+322 m X+402 m X+492 m X+577 m X+640 m

(17 PICD)(8 PICD)(11 PICD)

X+247 m

(9 PICD) Blank pipe Blank pipe

Figure 2. Detail of a horizontal completion with ICDs (upper) and CT placement to spot diverter across high permeability zones (after Thomas et al. 1998)

Table 1. Acid/diverter placement strategies for horizontal wells

Location of the fractured/thief

zone in the horizontal well section Acid placement strategy

Bullheading with diverter

Bullheading without diverter

Coiled tubing with diverter and annular injection Zone 1,2 or 3 (Figure 2)

Coiled tubing with diverter and No annular injection


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Figure 3 shows horizontal-well treatment data for wells with a thief zone located in the middle portion of the

horizontal section for bullheading without and with diversion, and CT with diversion down the tubing and down the tubing and annulus techniques (Thomas et al. 1998). It is observed that the CT allows distributing the treatment more uniformly along the wellbore. Thomas et al. (1998) also found that bullheading the acid with diverter usually results in poor zone coverage beyond 90 m to 120 m, as apparently, the acid rapidly creates a thief zone near the heel of the horizontal well, making conventional chemical diversion ineffective.

Figure 3. Distribution of HCl (gallons per foot of reservoir) for various placement and diversion techniques (after

Thomas et al. 1998)

3. Case Studies 3.1. Case 1: Bullheading

The first case is an extended-reach horizontal producer drilled in a mature naturally-fractured-carbonate reservoir. Partial and total mud loses were experienced while drilling the horizontal section of 800 m length, consisting of a large number of natural fractures (Figure 4). The location of the fractures coincided with the zones of lost circulation, as highlighted in the seismic cube (Figure 5). The completion strategy for this well consisted of isolating the fractured zones with blank pipes and IPs to prevent the rapid flow of gas and water, and to allow a more uniform sweep of the matrix through the ICDs. The well was completed with a 5 in. liner, 45 ICD and 9 Inflatable Packers (IP).

Figure 4. Example of a FMI log showing fractured sections

Figure 5. Maximum-curvature seismic image highlighting the lost circulation zones coinciding with

the natural fractures

The fine solids in the mud were deposited in the face of the permeable areas, in this case the natural fractures.

To disperse the low-density polymeric mud absorbed by the rock walls and to remove the organic deposits generated in the well vicinity, a volume of 90 m3 of organic solvent was first bullheaded in the producing interval of 780 m. This was intended to dissolve the organic deposits and to maintain them in solution, leaving the rock and fines water wet,


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lowering the interfacial tension when mixing with the spent acid to prevent emulsions, and to facilitate the rapid flow of the returns. The organic treatment was followed by 90 m3 of 10% HCl to dissolve the inorganic damage in an estimated radius of 0.9 m along the wellbore. An admission test using diesel was conducted prior to the stimulation job, beginning with a rate under 0.25 bpm up to 8 bpm, with a volume of 15 m3. Tracers were used throughout the job. Formulation of each stage is presented in Table 2. The operational program consisted of bullheading the treatment through the static CT with the well closed, as per the sequence shown in Table 3.

Table 2. Pumping schedule (organic and inorganic phases)

HCl - 10 %: Volume 90 m3 Aromatics solvents: Volume 90 m3

System Concentration (%) System Concentration (%)

Anti sludge 1.0 Aromatic solvents 91.0 Dispersants 1.0 Mutual solvents 5.0

Corrosion inhibitor 2.0 Surfactants 1.0 Surfactants 1.3 Asphaltene dispersants 3.0 Clay inhibitor 0.7 10% HCl 93.0 Foamy 0.5 Ferric Ion scale control 0.5

Table 3. Stimulation program Case 1

Stage Fluid Volume

(m3)

N2 rate

(m3/min)

Liquid rate

(BPM)

Bottom rate

(BPM) Quality Tracer

1 Nitrogen 6,164 30 to 100 0 2 to 8 100 2 Organics diluents 30 0 2 2 0 Antimony 3 Organics diluents 30 0 3 3 0 Antimony 4 Organics diluents 30 0 5 5 0 Antimony 5 10% HCl 30 0 2 2 0 Iridium 6 10% HCl 30 0 3 3 0 Iridium 7 10% HCl 30 0 5 5 0 Scandium 8 Nitrogen 6,164 30 to 100 0 5 to 8 100

During the first and last stages of the job, Nitrogen was circulated through the CT at a maximum rate of 100 m3/min, making sure that the pumping pressure did not exceed 3000 psi. The solvent was overflushed into the formation. Once the pumping finished, the well was circulated and lifted with the assistance of CT. Figure 6 is a plot of the main variables measured during the stimulation job, including surface pressure, pump volume, pumping flow rate and Nitrogen flow rate. Figure 7 is a portion of a production log showing a very good distribution of the treatment in the formation. Notice that in this case it was not necessary to use chemical divergence as the ICDs provide sufficient mechanical divergence effects.

Stage in formation

Entering to formation

In Wait program confirmation

10% HCL entering to formation

Aromatic solvent entering to formation

Stages

6164 m3 N2

30 m3 Aromatic solvent



30 m3 10% HCL

30 m3 10% HCL

30 m3 10% HCL


Sweeping of you line

6164 m3 N2

Finishes operation

Pressure (psi)Pump volume (bbl)

Rate pump (bpm)N2 rate (scmm)

Figure 6. Stimulation job log for Case 1

Figure 7. Portion of a PLT log showing a fairly uniform distribution of tracers in the formation (yellow-Scandium/blue-Antimony/red-Iridium)


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3.2 Case 2: Bullheading and Coiled Tubing

The second case is also a horizontal producer drilled in a naturally-fractured reservoir, and completed with a 5 in. liner, 21 ICD and 12 IP. Partial and total mud loses were experienced while drilling the 720 m horizontal section. The completion strategy responded to the same needs as in the first case. A stimulation treatment was designed to disperse the low density polymeric mud absorbed by the rock walls and to remove the damage caused by the fines housed in the fractured network near the wellbore. Prior to the stimulation job, it was necessary to verify the integrity of the IP, part of the ICD completion system, by pumping 2% KCl water with a tracer, making use of a CT unit. A production log was then run to detect the position of the tracer in the reservoir. An initial batch of 30 m3 (Table 4) was pumped in order to dissolve the organic deposits and to maintain them in solution, leaving the rock and fines water wet, lowering the interfacial tension when mixing with the spent acid to prevent emulsions, and to facilitate the rapid flow of the returns. The organics treatment was followed by a second batch of 90 m3 of 15% HCl to dissolve the formation damage associated to calcareous particle deposition. Figure 8 shows a plot of the main variables of the clean up portion of the treatment, placed with the assistance of CT.

Table 4. Initial clean-up mixture

System Concentration (%)

Antisludge 1.0

Dispersants 1.0

Corrosion inhibitor 2.0

Surfactants 1.0

15% HCl 74.0

Foamy 0.5

Ferric ion scale control 0.5 Organics diluents 20.0

11/19/200821:00 22:00 23:00

11/20/200800:00 01:00

11/20/200802:00

Time

0

1000

2000

A

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

4.0

4.5

5.0B

0

10

20

30

40C

Presion (psi) Gasto de bombeo (bpm)Volumen Bombeado (bbl)

A BC

171615

14

131211109876543

Figure 8. ICD cleaning log, treatment placed with CT

The next step in the process consisted of bullheading 90 m3 of 15% HCl as a non-gelid system, and tracers for

monitoring. Table 5 and Figure 9 show the pumping sequence and a log of the main variables of the stimulation treatment, respectively.

Table 5. Bullheading matrix treatment – First treatment

Stage FluidVolume

(m3)

Rate N2

(m3/min)

Liquid rate

(BPM)

Bottom rate

(BPM)

Quality

(% )

Volume

(m3 std)

Rel.N2/liq

(m3 std/m

3)

Time

(min)Tracer

1 Nitrogen 102.57 230 16 100 9000 39

2 HCl+Organic mater dilution 20 230 4 20 80 7234 362 32 Iridium

3 HCl+Organic mater dilution 20 230 6 22 75 5261 263 23

4 HCl+Organic mater dilution 20 230 7 23 70 4133 207 18

5 HCl+Organic diluent 15 230 9 25 65 2411 161 11

6 HCl+Organic diluent 15 230 11 27 60 1973 132 9 Scandium

7 Nitrogen 79.78 230 16 100 7000 30

Total 272.35 37012 161


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11/20/200813:00 13:30 14:00 14:30 15:00 15:30 16:00

11/20/200816:30

Time

250

500

750

1000

1250

1500

1750

2000

A

0

5

10

15B

50

100

150

200

250

300

C

100

200

300

400

500

DPresion (psi) Gasto de bombeo (bpm)Volumen Bombeado (bbl) Gasto N2 (scmm)

A BC D

9876543

Figure 9. Stimulation job log for Case 2, First treatment - Bullheading

A production log was run after the job to find out whether the treatment effectively stimulated the ICD

exposed flow areas, marked in green in the log of Figure 10, by identifying the placement of the tracers. It is observed low to negligible admission in the bottom interval (left log), top interval (right log) and upper portion of the bottom interval (right log)

Figure 10. Portion of PLT log after the matrix treatment

It was concluded at this point that the damage associated to the polymeric mud loses occurring before the

placement of the ICD completion could not be removed. It is also possible that the diesel clean-up operation with the well closed resulted in emulsions and organics precipitates. The contact time of the solvent during the clean up operation was likely null. The poor results of the bullheading stimulation were confirmed by the unstable well behavior during the lifting operation, performance considered typical of a damaged well.

Strongly emulsified surface samples were obtained and taken to the lab to identify suitable solvents and acids to break the emulsion in preparation for a remedial field work. A second matrix stimulation treatment was formulated, consisting of three stages, one for clean up purposes, and two for stimulation purposes. The first stage consisted of bullheading 100 m3 of organic solvents with foam of quality ranging from 60% to 80% as divergence, and contact time of about 4 hours to remove organics deposits. The pumping sequence is shown in Table 6 and a plot of the main variables of this stage is shown in Figure 11.

Table 6 Bullheading matrix treatment – First stage of the second treatment (Clean up)

FluidVolume

(m3)

Liquid rate

(BPM)

Bottom rate

(BPM)Quality

Volume N2

(m3 std)

Rel. N2/liq

(m3 std/m

3)

Time

(min)

Organics diluents 20 3 3 0% 42

Organics diluents 20 5.5 14 60% 2630 362 23

Organics diluents 20 6.5 19 65% 3290 263 19

Organics diluents 20 6 20 70 4193 207 21

Organics diluents 20 4 20 80% 6919 161 32

Nitrogen 103 16 100% 9000 132 39

Total 203 26033 176


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Figure 11. Stimulation job log for Case 2, First stage of the second treatment - Bullheading

The second stage of the remedial treatment consisted of placing a volume of 20 m3 of a 15% HCl plus organic

solvents in each of the ICD with the assistance of CT. Finally, the last stage consisted of bullheading 100 m3 of a mix of HCl with mutual solvents with foam of quality ranging from 60 to 80% as divergence, also to dissolve organic deposits. The pumping sequence is shown in Table 7 and the main operational variables are shown in Figure 12.

Table 7 Bullheading matrix treatment – Third stage of the second treatment

Fluid Volume

(m3)

Liquid rate

(BPM)

Bottom

rate (BPM)

Quality

(%)

Volume N2

(m3 std)

Rel. N2/liq

(m3 std/m3) Time (min)

HCl+Organics diluents 20 5.5 14 60 2,630 362 23



Organics diluents 20 4.0 20 80 6,919 161 32 Nitrogen 103 16 100 9,000 132 39

Total 203 29,494 192

Figure 12. Stimulation job log for Case 2, Third stage of the second treatment - Bullheading

Results of this second treatment were significantly better than before. Initial indications were observed while

circulating and lifting the well, observing a smooth behavior of the wellhead pressure and flow rate. The well stabilized at 6,200 BOPD. 4. Conclusions

The introduction of horizontal ICD completions in naturally-fractured carbonates opened new challenges for the customary process of stimulating the wellbore to remove the damage induced during the drilling phase. Programs require customized fluids and more elaborated placement mechanisms in order to successfully treat the damaged portions of the well, and to be able to remove the spent products. The following conclusions can be drawn based on actual field examples:


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• Field experience in conventional horizontal wells indicate that bullheading the matrix treatment from the surface is not effective, even with diverter, as most of the acid is spent in the top 90 to 120 m of reservoir. In the first case presented here, the ICD system proved to work effectively as mechanical diversion in bullheading pumping treatments.

• In cases where the stimulation treatment was conveyed with the assistance of coiled tubing, it was found that it was relatively straightforward to place the treatment selectively, however the penetration of the fluids was limited to the near wellbore area.

• In cases where the treatment was bullheaded using foam of different qualities as diverter, it was found that significantly better divergences, as well as bigger penetrations in the formation, were achieved.

• Tracers proved useful to determine the distribution of the treatment along the horizontal section of the well. • It is important to run compatibility tests with an actual crude sample. Equally important is a job design with

sufficient reaction times and prompt removal of the spent products. • This study found that the most relevant parameter for a successful acid stimulation in horizontal naturally-

fractured-carbonate wells is the accurate placement of the treatment in the intervals of interest and application of diversion techniques, as opposed to the general belief that is the volume of acid.

5. References Chesson, J., Cawiezel, K. and Devine, C.: “Diverting Acid for Better Stimulation”, E&P, February 20, 2008. Mitchell, W.P., Stemberger, D. and Martin, A.N.: “Is Acid Placement Through Coiled Tubing Better Than Bullheading?”, paper SPE 81731, presented at the 2003 SPE/ICoTA Coiled Tubing Conference, Houston, Texas, 8-9 April.

Nasr-El-Din, H.A., Al-Habib, N.S., Al-Mumen, A.A., Jemmali, M. and Samuel, M.: “A New Effective Stimulation Treatment for Long Horizontal Wells Drilled in Carbonate Reservoirs”, paper SPE 86516, SPE Production and Operations, Aug. 2006, pp. 330-338.

Raffn, A.G., Zeybek, M., Moen, T., Lauritzen, J.E., Sunbul, A.H., Hembling, D.E. and Majdpour, A.: “Case Histories of Improved Horizontal Well Cleanup and Sweep Efficiency With Nozzle-Based Inflow Control Devices in Sandstone and Carbonate Reservoirs”, paper OTC 19172, presented at the 2008 Offshore Technology Conference, Houston, Texas, 5-8 May.

Safwat, M., Nasr-El-Din, H.A., Dossary, K., McClelland, K. and Samuel, M.: “Enhancement of Stimulation Treatment of Water Injection Wells Using a New Polymer-Free Diversion System”, paper SPE 78588, presented at the 10th Abu Dhabi International Petroleum Exhibition and Conference, Abu Dhabi, UAE, 13-16 October, 2002.

Saxon, A., Chariag, B. and Abdel Rahman, M.R.: “An Effective Matrix Diversion Technique for Carbonate Formations”, paper SPE 62173, SPE Drilling and Completion, Mar. 2000, pp. 57-62.

Schlumberger “Carbonate Stimulation”, Middle East and Asia Reservoir Review, Number 8, 2007, pp. 50-63. Thomas, R.L. and Milne, A.: “The Use of Coiled Tubing During Matrix Acidizing of Carbonate Reservoirs”, paper SPE 29266, presented at the 1995 SPE Asia Pacific Oil and Gas Conference, Kuala Lumpur, Malaysia, 20-22 March.

Thomas, R.L., Saxon, A. and Milne, A.: “The Use of Coiled Tubing During Matrix Acidizing of Carbonate Reservoirs Completed in Horizontal, Deviated, and Vertical Wells”, paper SPE 50964, SPE Production and Facilities, Aug. 1998, pp. 147-162.

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