Paper 54722 - Insol Pdvsa

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Copyright 1999, Society of Petroleum Engineers Inc.

This paper was prepared for presentation at the 1999 SPE European Formation DamageConference held in The Hague, The Netherlands, 31 May1 June 1999.

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, aspresented, have not been reviewed by the Society of Petroleum Engineers and are subject tocorrection by the author(s). The material, as presented, does not necessarily reflect anyposition of the Society of Petroleum Engineers, its officers, or members. Papers presented atSPE meetings are subject to publication review by Editorial Committees of the Society of Petroleum Engineers. Electronic reproduction, distribution, or storage of any part of this paper for commercial purposes without the written consent of the Society of Petroleum Engineers isprohibited. Permission to reproduce in print is restricted to an abstract of not more than 300words; illustrations may not be copied. The abstract must contain conspicuousacknowledgment of where and by whom the paper was presented. Write Librarian, SPE, P.O.Box 833836, Richardson, TX 75083-3836, U.S.A., fax 01-972-952-9435.

AbstractAs a result of less than expected productivity from some wellsin the El Furrial field in Monagas State in Eastern Venezuela,a systematic study became necessary. The results of the studywere aimed at determining formation damage preventionguidelines for existing and future wells, and effectivetreatment measures for damaged wells.

The joint study was undertaken by PDVSA Exploracin &

Produccin in Maturin, Venezuela and Core LaboratoriesReservoir Optimization Services Group (ROSG) in Houston todetermine the existing formation damage mechanisms. The

primary objective was to recommend non-damaging drilling,completion and stimulation programs in this troublesomereservoir system.

The study included the review of drilling, completion andstimulation records as well as log analysis and well testevaluation for productivity potential estimation. Laboratoryanalysis to investigate possible sources of formation damage,evaluation of drilling mud systems and the design of astimulation recipe was also a major part of this study.

A description of the laboratory tests employed in theevaluation of the potential and degree of impairment from thedifferent mechanisms is presented along with interpretationsand scaling of laboratory data to field operating conditions for

pilot application design.

The study shows that the dominant damage mechanism in thisfield is organic scaling and associated problems. The crude oilcontained in the reservoirs of this field has gravity ranging

from 20 to 30 API, bubble points from 2,000 to 4,500 psi,asphaltene contents from 2 weight percent (at the top of thereservoir) to 20 weight percent (at the bottom), and about 4mole percent of CO 2.

The laboratory study shows that the current average reservoir pressures for the pertinent formations are dangerously close to

their respective asphaltene flocculation onset and damagingconditions.

On the basis of the laboratory studies, two field pilots wereundertaken. One to evaluate the effectiveness of thestimulation recipe designed for the system and the other to testthe effectiveness of the drilling mud formulation determinedin the laboratory.

Removal of asphaltene from the reservoir matrix through theuse of InSol A/W TM mixed in xylene was found to be effectiveas a dispersant/solvent as well as an inhibitor.

Well selection and pre-stimulation activities for the first pilotare presented along with the chronological summary of activities. The paper presents the post treatment evaluation,indicating that the increase in productivity is in the range of 250%. The longevity of the treatment was monitored and isalso discussed.

The drilling pilot was based on a laboratory study whichindicated that an invert emulsion mud system, with CaCOand barite as bridging agents, would effectively reduce theamount of filtrate lost to the formation and hence reduce thedamage caused during drilling. Paramount to the effectivenessof the mud system is the distribution of the solid bridgingagents required through the zones of interest. The base linedistribution and envelope to maintain this distribution wasdetermined from laboratory studies of pore size and structure.

The methodology used and some of the drawbacksencountered with taking the laboratory results to actual

practice in the field are highlighted. Post drilling andcompletion results are summarized with comparisons made toother similar wells in the field that were drilled and completed

before and after the pilot.

SPE 54722

Systematic Formation Damage Evaluation of El Furrial FieldHenry A. Ohen, Thais Moreno, Desdebura Marcano, Armando Acosta, Raul Mengual, Jose Gil, Adela Velasquez, Dane Daneshjou,Kosta Leontaritis, Mike Holmgren


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2 HENRY A. OHEN, ET AL SPE 54722

We show that the benefit of this integrated systematicapproach is that it enabled the design of a drilling mud andstimulation program based on laboratory experiments rather than field trials.

IntroductionThe El Furrial field is located in Monagas State in EasternVenezuela about 25 km from Maturin. Crude oil is producedfrom the Naricual and Los Jabillos Formations at depthsranging from 13,000 to 16,000 feet. The recorded averagereservoir pressure and temperature of the formations atdiscovery were approximately 12,000 psi and 308 Frespectively. The discovery well, Well-1, was tested in the

Naricual formation at an interval of 13,690 to 13,842 feet inMarch 1986 and indicated a pressure of 11,276 psi at a datumof 13,800 feet. 1 The reservoir pressure had dropped to 7,500

psi in the Naricual after eight years of production. That is aloss of about 3,800 psi in the reservoir pressure or an averageof 472 psi pressure drop per year.

In 1997, after years of experiencing less than expected productivity from the wells in the field, this study was initiated by PDVSA and Core Laboratories for the assessment andcontrol of the observed formation damage problems in theField.

Objectives of the StudyThe following three main objectives were defined for thisstudy:1. Determine the dominant formation damage mechanism in

the El Furrial Field.2. Determine non damaging drilling and completion fluid(s)

for wells in this field.3. Determine an effective stimulation recipe for damageremoval for wells in the field.

To achieve these objectives, following study program wasestablished.

Well selection for the study. Selection of core material for laboratory testing. Initial discussions and evaluation of drilling mud for the

best possible drill-in fluid. Initial discussions and evaluation of chemicals for the best

asphaltene inhibitor and solvent/dispersant.

Well by well review of drilling, completion andstimulation processes. Well by well evaluation of petrophysical data and well

potential Laboratory static and dynamic testing for damage

assessment Recommendation for the stimulation pilot well Recommendation for full scale implementation of the

drilling mud pilot well

Formation Damage AnalysisTo help understand the time, location and mechanisms of formation damage in the field, fourteen wells withcompletions in the four different formations of the Naricualand Los Jabillos formations were selected for detailed study asshown in Table 1. Rock and fluid samples were also selectedfor laboratory analytical work.

Preliminary Data EvaluationPDVSAs geologists and operation engineers, along with CoreLaboratories personnel, selected the wells for the study. Theselected wells and the zones of completion are shown in Table1. Wells within a cross-section of the field that have had someformation damage problems were selected. Drilling,completion and stimulation records, pressure, productionand/or in jection well h istories were obtained for review.

Pretrophysical data including well test data were also obtainedfor review. Available core analysis database was reviewed

with the aim of obtaining the most representative samples for dynamic flow study based on the 1996 petrophysical modelfor the El Furrial field by Core Laboratories 2.

A systematic review of the well files was initiated with thegoal of identifying formation damage problems. The data wascollected on a well by well basis. Typically, the drillingreports included mud weight, funnel viscosity, plasticviscosity, yield point, gel strength, percentage of solid-oil-water, pH levels and additive. A complete description of important drilling and completion events was compiled for each well. Review of the production history indicated thatmost of the wells experienced formation damage during the

drilling, completion and production phases of welldevelopment.

Petrophysical Evaluation by the Hydraulic UnitsMethodIn order to determine the potential of a well, the permeabilityof the completion zone must be know as well as thehydrocarbon properties and the completion configuration. Toobtain average permeability and net reservoir sand, thehydraulic units based petrophysical model developed in 1996

by Core Laboratories 2 was used and shown in Flowchart 1.

Figure 1 shows the comparison of the well test permeability toCore-Log permeability in wells where well test data wereavailable. The near perfect match validates the method of calculating and averaging permeabilities per zone.

Productivity Index CalculationThe radial flow of a single homogeneous liquid of smallcompressibility contained in a uniform horizontal reservoir into the wellbore can be represented by the following inflow

performance equation.


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Whole Mud AnalysisStatic Parametri c Test on D ri ll ing and Completions

Fluids Static parametric test was performed on four water baseddrilling mud and two oil based drilling mud for screening

purposes. The tests were performed according to flowchart 6.

Data obtained during the static parametric testing the result inthe following ranking

1 Oil base mud -Company Y1a Oil base mud -Company X2 Na/KHCO 2 Water base mud -Company X3 NaCl/NaBr Water base mud -Company X4 KHCO 2 Water base mud mud -Company Y5 CaCl 2 Water based mud mud -Company Y

Dynamic Test on Dril lin g Flui ds Los Jabillos oil, being the poorest oil sample, was used for

whole mud testing to obtain the worst case scenario. Acomposite core holder approximately 2 feet long with three pressure taps was used in the test according to the procedureshown in flowchart 7.

Results of Testing.Table 6 is a summary of the leak off, return permeability and

breakdown pressure tests for the two water based and two oil based drilling mud systems. Figure 9 is a plot of flow rateversus differential pressure for all the muds tested. As shownin Table 6, mud cake breakdown pressures are 25 psi, 17 psi, 1

psi and 11 psi for Company B calcium chloride (CaCl 2) water- based mud, Company Y K/Na-Formate (Na-KHCO

2) water-

based, Company Y oil based, and Company X oil basedrespectively.

These results indicate that the water-based mud is not the bestfor this rock and fluid system. The best mud system appears to

be either of the oil-based mud. However, the Company Y oil based mud cleans up better without the need for mud cake breaker (surfactant, mutual solvent etc). The return permeability at the injection end for Company Y oil based mudis 23% compared with 5.5% for Company X oil based mud.

On the basis of these tests, the mud systems are ranked as:

Oil base mud (Company Y)Oil base mud (Company X)KHCO 2 Water base mud (Company Y)CaCl 2 Water based mud (Company X)

Thi n Section Petrology Thin sections of the cores, after being exposed to drilling mud,were obtained from the upstream samples in the composites tohelp identify the damaging mechanisms from exposure to

mud. Three more thin sections were made from companionsamples to compare with the invaded upstream samples in thewhole mud testing. Examples of the damaged and undamagedthin sections are shown in Figure 10. The seven core plugsamples were analyzed to determine the depth of invasion of drilling mud solids after laboratory whole mud testing. Threeof these plug samples were pre-test samples analyzed to

determine the nature and distribution of naturally occurringclays as well as other pore-filling cements. Four of the plugsamples were used as the upstream sample in the whole mudtesting. Each of these plugs was cut in half, perpendicular toits length. A longitudinal thin section was then made of eachhalf. Each sample was compared with the undamaged core

plugs to determine the extent of possible drilling mud solidsinvasion. The documentation of the depth of invasion isshown in the Table 7.

Review of the return permeability data shows a great contrastin permeability reduction as a function of the type of drillingmud used. The thin section petrographic data indicate thatdrilling mud solids invasion is not a significant factor contributing to the return permeability reduction. Theamounts of pore-lining clays, which are of illitic or mixed-layer composition, may be a part of the reason for

permeability reduction. The fact that the water-based drillingfluids had greater permeability reduction than the oil-basedmuds also supports possible adverse clay-filtrate reactions.Mineralogical analysis (XRD) previously 2 performed inWELL-13 indicates kaolinite, illite and mixed layer illite/smectite are in that order the dominant authigenic claymineral in these samples.

Reservoir Condition OptimizationTwo static tests were performed to evaluate the effects of mudfiltrate on the optimum mud system. The tests were designedto show asphaltene drop out or change the onset pressure of asphaltene flocculation when the mud filtrate comes intocontact with the reservoir oil. The Los Jabillos live crude oilwas used in all the static tests performed in this section.

Two static tests were performed to evaluate the effect of mudfiltrate on the crude oil asphaltene flocculation. In the firsttest a sample of the Los Jabillos live crude oil (30 cc) wasrestored at 9,000 psi and 300 F for one week. Then, the

pressure was lowered to 7,000 psi while the restored live crudeoil sample was titrated with the Company Y mud filtrate up to170 percent by volume. The NIR measurements were recorded

continually. No asphaltene flocculation occurred due toaddition of mud filtrate at constant pressure above the onset

pressure value. This indicates that Company Y drilling mudfiltrate will not cause asphaltene drop out as long as thedrilling operations are above the flocculation pressure (drillingoverbalance).

In order to establish the onset value of the mud filtrate andcrude oil mixture a second static test was performed. In this


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SPE 54722 SYSTEMATIC FORMATION DAMAGE EVALUATION OF EL FURRIAL FIELD 7

test, 15 cc of mud filtrate was added to 30 cc of restored livecrud oil at 7,000 psi and 300 F. Then pressure was reducedto measure the onset value of the mixture. The onset value of the WELL-52 live oil and mud filtrate mixture was measuredat 6,150 50 psi which is 800 psi higher than that of the pureWELL-52 Los Jabillos oil. This indicates that the mud filtratemade the asphaltene unstable by increasing the asphaltene

onset pressure of WELL-52 live oil and causing the asphalteneto flocculate earlier. The result of this test is presented inFigure 11.

Field PilotsStimulation PilotEffective removal of asphaltene from the reservoir matrixthrough the use of InSol A/W TM mixed in xylene, at aconcentration of 10%, was one of the major recommendationsof the laboratory study. Numerous wells were evaluated usingnodal analysis program to determine the productivity increasethrough the use of this chemical mixture. After carefulconsideration, the Well 10 Inferior was chosen as a pilot well

for stimulation. Figure 12 shows the mechanical condition for the completion of Well 10 Inferior. Flowchart 8 shows the proposed procedure and actual chronology for the field pilot.

Post Stimulation Performance Nodal analysis for the well, both pre-treatment and posttreatment were prepared. The pre-treatment results are shownin Figure 13. At the producing conditions of 700 BPD, 980 psiwell head pressure, a GOR of 1,583, and a choke of , the

bottom hole flowing pressure is approximately 3,755 psi. This pressure is well below the flocculation onset pressure of 5,300 psi. The post treatment evaluation for the conditions of 1,470BPD, 1,240 psi well head pressure, a GOR of 1,583, and a choke is shown in Figure 14. In this case, the flowing bottomhole pressure is approximately 4,575 psi, only 725 psi belowthe estimated flocculation onset pressure. Figure 15 shows the

pre-stimulation rate and three post stimulation rates monitoredto investigate the longevity of the treatment.

We have shown in the laboratory study of the inhibitor that theflocculation onset would be decreased by some 1,550 psi

below the actual onset pressure with InSol A/W TM treatment.This would indicate that a flowing bottom hole pressure of around 4,600 psi would be safe for producing the well. This isclose enough to the current estimate of bottom hole pressure toallow production on a choke.

Mud PilotPreliminary DevelopmentOne of the primary objectives of the study was to evaluatedrilling and completion fluids in order to develop non-damaging formulations for use in a pilot well. Results fromleak-off tests, return permeability measurements, and

breakdown pressure tests also indicated the oil based(Invermul) drilling fluid was better than the water based fluid.

The drilling mud recommended for use in the drilling pilotwell, Well-79, was VESADRIL. The mud is an oil-in-water emulsion that has been shown to be very stable in thelaboratory at the anticipated formation temperatures and

pressures. Addition of calcium carbonate, CaCO 3, controls thefluid leak-off and barite controls the mud weight. The mudformulation initially tested in the laboratory is shown in Table

8.

This mud formulation results in a drilling mud with a reportedweight of 12.0 ppg, viscosity of 37 cps, and a fluid loss of 3.0to 3.6 ml for a 2,000 psi differential pressure.

The key to the success of the mud system is the bridging of pore throats by the CaCO 3 and barite. Using a Coulter LSParticle Size Analyzer, the particle size distribution wasdetermined and reported as 1.770 m for D10, 20.24 m forD50, and 72.23 m for D90. Figure 16 shows the base particlesize distribution.

Design Prognosis and ModificationsThe use of a 12.0 ppg mud weight had been based upon the premise the well would be drilled through the Los Jabillosformation. However, as the target formation is Naricual, amaximum mud weight of 11.0 ppg was formulated for fieldapplication. A portable laser particle size couner unitmanufactured by Spectrex, the PC-2000, was used in the fieldto determine the bridging particle size and ditribution

Quality Control MeasuresMonitoring the drilling mud for the quality control of particlesize distribution and conformance to mud weightrecommendations were the objectives set forth for CoreLab.

Figure 17 shows Figure 16 with lines having circle markersrepresenting the envelope within which the particle size isconsidered acceptable. This chart is the guideline for checking the mud tests.

Five tests for each mud sample were evaluated with theSpectrex. The average result of the five tests was thenrecorded as the value for the interval. With the eccentricities

previously mentioned for the D 5 and D 95 readings, the D 5reading was used as the determining factor for the time torequest addition of CaCO 3 or to run the centrifuge . Table 9 isthe summary for the mud tests showing the daily mud weight,viscosity, solids, salinity, water loss, and particle sizedistribution. Below the titles is the acceptable range for each

parameter as originally submitted to PDVSA by Company Y.Viscosity, solids, and salinity were consistently below therecommended values and mud weight was consistently higher than recommended. However, there were no adverse problemsas a result of the low viscosity, solids, and salinity. The higher mud weight led to concern that excess water loss to theformation might occur. Figure 18 shows the mud weight,hydrostatic pressure of the mud, and reservoir pressure as afunction of depth. The formation pressure is from the


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formation tests taken after logging of the well. The calculatedfluid density for the reservoir pressure is about 8.6 ppg.

Results The preliminary results reported are that the well was asuccess having initial production of over 7,000 BOPD. On

November 5 th and 6 th the well was flow tested on three choke

sizes then shut in for a pressure buildup test. Figure 19 showsthe flow rate for oil and the flowing wellhead pressure. Table10 shows a comparison of specific productivity indices (SPI)for three pre-pilot wells and two post pilot wells with the pilotwell. The results show the superior performance of the pilotwell. Figure 19 depicts these results graphically.

ConclusionsFormation damage problems in El Furrial wells is somewhatrelated to drilling and completions but is mostly due to

production operations.

Laboratory tests show water-based drilling fluids have greater

permeability reduction than oil-based drilling fluids due to possible adverse clay-filtrate reactions. This is supported by previous mineralogical analysis (XRD) which indicateskaolinite, illite and mixed layer illite/smectite are, in thatorder, the dominant authigenic clay mineral in these samples.The thin section petrography data performed in this study alsoindicates significant amounts of pore-lining clays, which areof illitic or mixed-layer composition.

Increased productivity can be obtained through the use of amixture of 10% InSol A/W TM in xylene to remove asphaltenedeposits in the formation matrix. Initial production increasedfrom 700 BPD to 1,740 BPD was observed in the pilot well.

Pre-treatment removal of asphaltene deposits in the tubing andsump is critical. Without proper pre-treatment cleaning of tublars and sump, production logs and buildup testing can not

be carried out. Additionally, knowledge of pre-treatmentflowing conditions is essential to properly time the flow back time after each stimulation stage.

Use of Calcium Carbonate has been proven effective as a bridging agent against fluid loss; inferring proper particle sizedistribution of CaCO 3 is needed to ensure effective bridging.This is evidenced from the fact that excessive pressuredifferentials due to high mud weight were maintainedthroughout the drilling yet apparent damage due to fluid loss

to the formation was negligible. The stability of the invertemulsion mud contributed to the limited damage.

RecommendationsIt is recommended that InSol A/W TM mixed at 10% in xylene

be utilized as a treatment for removing and inhibiting theformation of asphaltene in the reservoir. Repeat treatments can

be scheduled periodically as well flow conditions warrant.

A drilling mud system with rheological properties and stabilitycriteria similar to the one used in the pilot is recommended for future wells in the field. The mud system should contain adistribution of coarse and medium sized Calcium Carbonate for

bridging along with barite for weight and filter cake formation.

Nomenclature

K Permeability in mD PI Productivity index in bbl/day/psi Bo Formation Volume factor ( rb/stb).S t Total skin .S p Partial Penetration Skin

H n Net sand thickness, ft r e Drainage radius, ft (1800 ft assumed)r w Wellbore radius, ft

Viscosity, cp (perforation density)*(perforation radius)

ht total thickness, ft hp perforated thickness, ft NS Naricual Superior NM Naricual Medio NI Naricual Inferior LJ Los Jabillos DP Pressure DropCL Core-Log Interpretation

NIR Near Infra Red SPI Specific Productivity Index, BPD/psi/ft

ACKNOWLEDGMENTThe authors thank PDVSA and Core Laboratories for the

permission granted to publish this manuscript. Additionalthanks is due Brian Stevens for performing the laboratorytests.

R EFERENCES1. Rodolfo Colmenares and Richard W. Smith; Short and Long

term Management of El Furrial Field, Venezuela, Paper SPE38781, P. 321 - 326, presented at the 73rd Annual SPEconference and exhibition, San Anthonio, Texas, October 5rd -8th, 1997.

2. Ohen H.A., Milton M., Uroza C., Jimenez M. PetrophysicalEvaluation and Hydraulic Units Zonation of the Naricual and LosJabillos Formations in the El-Furial Field Final report presentedto Lagoven.

3. Advances in Formation Damage Control Strategies, Corelaboratories internal publications

4. Saidikowski, R.M. Numerical Simulation of the CombinedEffects of wellbore Damaged and partial penetration, SPE 8204.

5. Reichert, C., Fuhr, B. J., and Klein, L. L., "Measurement of AsphalteFlocculation in Bitumen Solutions." Journal of Canadian PetroleumTechnology, Sept.- Oct., 1986, p. 33.

6. 1992 El Furrial Formation Damage Study, Lagoven S.A. andCore Laboratories


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Averaging Permeability from

Hydraulic Units

The hydraulic units zonationand permeability prediction for

each zone w ere estimated

The perforated zones andthickness w ere identified

The RQI values w ere calculated for every 0.5 ft from the petrophysical

model

By comparing Well Test analysis topetrophysical data, RQI cut off 0.3,

0.4, 0.26 and 0.2 w ere used todetermine net sand for each

formation

The permeability w as averaged byhydraulic units and the net sand

thickness w ere summed up

The average permeability per zone w as obtained asthickness w eighted HU

permeability

Flowchart 1


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Asphaltene Inhibitor Testing

Measure AshalteneContent of Los Jabillos

surface sample oil

Titrate Surface oil samplew ith Heptane to determinebaseline NIR absorbance

Titrate Surface oil sample w ith250,500,1000,2000 ppminhibitor chemical B and

measure NIR absorbance

Titrate Surface oil sample w ith250,500,1000,2000 ppminhibitor chemical A and

measure NIR absorbance

Titrate Surface oil sample with250,500,1000,2000 ppm

inhibitor chemical C andmeasure NIR absorbance

Titrate Surface oil sample w ith250,500,1000,2000 ppm

inhibitor chemical D andmeasure NIR absorbance

Finally compare the results w ith the untreated baseline measurement and select the best concentrationsand rank the chemicals using best tw o for dispersant

testing

Flowchart 2


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SPE 54722 SYSTEMATIC FORMATION DAMAGE EVALUATION OF EL FURRIAL FIELD 11

Flowchar2

Reservoir Fluid Analysis TestingBottom Hole Samples

Sample Well Formation

1 Full-52 LJ2 Full-16 Sup.

Restoration of two bottom hole samples to300F and 9000 psi

API Gravity, Compositional and PARAanalysis for both bottom hole samples

Asphaltene deposition envelop for Full-52 (LJ)

Onsets for naricual for Full-16 (Sup.)

Surface Samples

Sample Well Formation

1 Full-48 LJ2 Full-51 Sup.3 Full-12 Inf.

API Gravity, Compositional and PARAanalysis on all three oils

Asphaltene drop outby extraneous fluids.

Initial screening testfor asphaltene

inhibitors.

Static parametric teston four drilling fluidsand three crude oil

samples.

Measure asphaltenecontent on Full-48surface virgin oil

Test each chemical A250, 500, 1000 and

2000 ppmMeasure asphaltene

content on 50/50mixture of Full-48 and

two water baseddrilling filtrates.

Measure asphaltenecontent on 50/50

mixture of Full-48 andtwo oil based drilling

filtrates.

Evaluate the resultand select the most

compatible mud.

Co. AChem A

Co. BChem B

Co. CChem C

Co. DChem D

Select the best twochemicals and test for dispersant properties.

Go to AsphalteneRemoval andPermeability

Recovery

Co. XWater Based Mud +Full-48, Full-51 and

Full-12Surface Samples

Co. XOil Based Mud +

Full-48, Full-51 andFull-12

Surface Samples

Co. YWater Based Mud +Full-48, Full-51 and

Full-12Surface Samples

Co. YOil Based Mud +

Full-48, Full-51 andFull-12

Surface Samples

Measure the viscosityof emulsion

Go to DataEvaluation and

Selection of Best Mud

Core Analysis TestingDrill 57 core plugs

Extraction cleaning and humiditydrying of all samples

Measure permeability andporosity by CMS300 at three

confining pressures(800, 2000, and NOB press.)

on all samples.

Measure liquid permeability atNOB selected samples

Select samples for Dynamic Testing

Thin section and Hg injection on

selected samples

Chemical #2Comp. #2 = Full-12 Sample 4

& Full-53 Sample 2

Whole Mud TestingUsing four composites and Full 48 Los Jabillos Oil

Full-48 Los Jabillos Oil andCo. X Oil based Mud

(CaCl 2)Composite 2 (C2) = Full-46

Sample 4& Full-46 Sample 2(Naricual Inferior)

Full-48 Los Jabillos Oil andCo. X Water based Mud

(CaCl 2)Composite 1 (C1) = Full-12

Sample 7& Full-53 Sample 4

(Los Jabillos)

Full-48 Los Jabillos Oil andCo. Y Water based Mud

(KHCO 2)Composite 3 (C3) = Full-53

Sample 6& Full-53 Sample 5

(Los Jabillos)

Full-48 Los Jabillos Oil andCo. Y Oil based Mud

Composite 4 (C4) = Full-2Sample 3

& Full-13 Sample 3(Naricual Superior)

Mud Optimization Tests - using BHS of oilsTest #1 Composite 1 (C1) = Full-12 Sample 8 (Los Jabillos)

Test #2 Composite 2 (C2) = Full-2 Sample 6 & Full-12 Sample 2 (Naricual Superior)

Asphaltene Removal and Permeability Recovery Test

Chemical #1Comp. #1 = Full-12 Sample 5

& Full-53 Sample 3

Select best inhibitor

Optimum Stimulation Testingusing 4 concentrations of m utual solvent

Test #1 (OSE1c1) and Test #2 (OSE2C2)

Final dataevaluation and

selection of the bestcombinations

Data Evaluation and Selection of the Best Mud

Input from StaticParametric Testing

Selection of the besttwo chemicals from

Initial Screening Testfor Asphaltene

Inhibitors.

Flowchart 2a


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Dispersant Properties Testing

Prepare stock of surfaceoil sludge (5 mg) and add

1,000 ml xylene

1 ml Stock + 100 mlhexane + 1,000 ml of # 1

Rank Chemical

1 ml Stock + 100 mlhexane + 1,000 ml of # 2Rank Chemical

Measuretransmittance

Measuretransmittance

Compare and Rank theChemicals

Flowchart 3


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Asphaltene Removal and Permeability Recovery Testing

Measure permeability to crudeoil and age the core samples

Load the composite rock samples ina core holder and charge the system

at above the asphaltene onsetpressure

Inject xylene to w ash through several PV o f the core to establish baseline for xylene

removal

Measure permeability at end of Xylene w ash

Apply the chemical dispersant atselected concentration in xylene to the

core samples

Measure sample permeability at end of Chemicaltreatment

Shut in the core for 24 hours and re-establishflow using xylene

Measure permeability at end of chemical treatmentand assess clean by comparing permeability

Reduce pressure below f locculation pressure andmeasure permeability to oil continuously in the

production direction until permeability reduction isobserved

Flowchart 4


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Dynamic Stimulation Test

Measure permeability to dead oil andage the core samples

Load the sample in a core holder and

charge the system at above the onsetpressure and measure permeability to

oil

Reduce pressure below f locculation pressure at specifiedincrements until permeability reduction is observed.

Measure permeability to oil continuously in the productiondirection..

Raise pressure back to above the onset pressure andmeasure permeability to oil and stop the oil flow after

system stabilizes

Inject 0.75 pore volumes of xylene w ith 1,500 ppmInSol A/W chemical additive.from the injection side

and let system soak for 4 hours then measurepermeability to oil.

Inject 1.5 pore volumes of xylene w ith 3000 ppmInSol A/W chemical additive from the injection side

and let system soak for 4 hours then measurepermeability to oil

Compare the permeabilities obtained in thedifferent steps above to evaluate the effect of xylene and chemical in removing asphaltene

damage

Flowchart 5


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Static Parametric Test

Obtain drilling filtrate for all the drillingmuds by the centrifuge process.

Prepare a mixture fifty percent byvolume of each drilling mud filtrate

and three surface oil samples

Let the mixtures settle for tw ow eeks and check for emulsion

phase periodically.

Mix the samples well and shake itfor at least 30 minutes then place

the samples into an oven at 300 F.

Repeat this for all the surface oilsand completion fluid (2% KCl)

Identify the sludge if present (sizeof sludge and asphaltene Content)

Measure viscosity of thesludge and the light end

mixture.

Flowchart 6


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Whole Mud Testing

Flow w hole mud for extended length of

time

Flush each sample w ithcrude oil and age 8 to 24hr (production direction)

Measure oilpermeability in the

production direction

Circulate sample with one of the drilling muds for 6 hrs

Shut in the sample for 6hrs

Flush sample with the drilling mud for 1 to 2 hrs. (injection direction)

Flush sample w ith oil in production

direction using step increases inpressure (starting w ith 2 psi) to get

breakdow n pressure

Provide continuous permeability andpressure data and periodic Compositional

analysis of collected effluent.

Flowchart 7


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Proposed Procedure Actual Procedure

Perform Production Test Log(PTL)

Prepare 10% InSol Mixture

Run Coiled tubing to bottom.Clean out Sump of w ell with

diesel if required.

Fill sump w ith 30 bblchemical mixture. Soak for 4

hours.

Open w ell and flow backchemical soak mixture.

Pull coiled tubing to mid-perforations and inject 500bbl chemical mixture at low

rate and below fracpressure. SWI for 4 hours.

Open w ell and flow backchemical squeeze mixture.

Inject 995 bbl chemicalmixture at low rate and

below frac pressure. SWIfor 4 hours.

Return well to production

Test well and run posttreatment PTL.

Attempted Production TestLog (PTL)

Prepared 10% InSol Mixture

Failed to get dow n due toasphaltene plugs in tubing

Run Coiled tubing to bottom.Jetted Sump and tubing up to

8,000'with diesel.

Fill sump and tubing up to8,000' w ith chemical mixtu re.Pull coiled tubing. Soak for 4

hours.

Open well and flow backchemical soak mixture.

Run coiled tubing to mid-perforations and inject 500bbl chemical mixture at 1

bpm and 3,850 psi pressure.Pull coil tubing. SWI for 4

hours.

Open well and flow backchemical squeeze mixture.

Run coiled tubing to bottomand inject 980 bbl chemicalmixture in 100 bbl stages at50' intervals. Pull coil tubing.

SWI for 4 hours.

Turn w ell over to PDVSA.Return w ell to production

Test well and run posttreatment PTL.

Flowchart 8


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Comparison of PTA and HU Permeabilities

1

10

100

1000

1 10 100 1000

Well T est Perm., mD

C o r e - l o g

P e r m . ,

m D

Fig. 1- Well test permeability verses core-log permeability

FUL- 52, Las Jabillos

0

1000

2000

3000

4000

5000

6000

7000

180 200 220 240 260 280 300 320Temperature, F

Bubble Point Upper Onset Lower Onset

No Solids Present

No Solids Present

Solids Present

Solids Present

Fig. 2- Asphaltene Deposition Envelope


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Asphaltene Flocculation TestFlu-48 STO + 1000 ppm Company D Chemical

-0.20

0.2

0.4

0.6

0.8

1

1.2

1.4

1.6

0.00 0.20 0.40 0.60 0.80 1.00 1.20 1.40 1.60 1.80 2.00 2.20

Amount of Heptane Added, cc's nC7 per gram Oil

R e

l a t i v e

N I R A b s o r b a n c

Onset at 0.225

Fig. 3- Example of asphaltene screening test

Dispersant Testing at 500 ppm Chemical Additivewith Ful-48 Tar in Hexane

-1

-0.8-0.6

-0.4-0.2

0

0.2

0.4

0.6

1500 1550 1600 1650 1700

Wavelength, nm

A b s o r b a n c e

Company BCompany DCompany CReference

Note:Higher absorbance means moredeposit dispersed

Dispersant Testing at 1000 ppm Chemical Additivewith FUL-48 Tar in Hexane

-1

-0.8

-0.6

-0.4

-0.2

0

0.2

0.4

1500 1550 1600 1650 1700

Wavelength, nm

A b s o r b a n c e

Company BCompany DCompany CReference

Note:Higher absorbance means more deposit dispersedwhich means better dispersant.

Fig. 4a- Ranking of chemicals at 500 ppm Fig. 4b-Ranking of chemicals at 1000 ppm


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B e f o r

e A g i n

g ( D e a d O

i l )

A f t e r

A g i n g

( l i v e O i l

)

A f t e r P r e

s s u r e

D r o p

( l i v e O i l )

X y l e n

e S t a r

t p o i n t

X y l e n

e E n d

p o i n t

X y l e n

e + C h

e m i c a

l S t a r

t p o i n

t

X y l e n

e + C h

e m i c a

l E n d

p o i n t

A f t e r T e

s t ( l i v e

O i l )

Composite1, CB Chemical

Composite2, CC Chemical

.0.

10.0.

20.0.

30.0.

40.0.

50.0.

60.0.

70.0.

80.0.

90.0.

100.0.

P e r m e a

b i l i t y a s

% o

f i n i t i a l p e r m e a

b i l i t y

Composite1, CB ChemicalComposite2, CC Chemical

Fig. 5-Asphaltene Removal and Permeability Recovery Testing

After aging- Initial base linePermeability(live oil) After Pressure Drop

asphaltene damage(liveoil) After injection of 1500 ppmchemical CC slug After injection of 3000 ppm

chemical CC slug

S1

.00.

10.00.

20.00.

30.00.

40.00.

50.00.

60.00.

70.00.

80.00.

90.00.

100.00.

P e r m e a

b i l i t y a s

% o f

i n i t i a l p e r m e a

b i l i t y

Fig 6- Dynamic Stimulation Test to Verify the Effectiveness of Chemical


22/32

BRIGING PARTICEL SIZE DATALos Jabillos

0.000

0.050

0.100

0.150

0.200

0.250

0.300

0.350

0.400

0.0010 0.0100 0.1000 1.0000 10.0000 100.0000

BRIDGING PARTICEL DIAMETER

M E R C U R Y S A T U R A T I O N ,

F R A C T I O N ( F R E Q U E N C Y

Ful 53 Sample 6

Ful 12 Sample 8

Ful 12 Sample 7

Average

Fig. 7- Bridging size distribution for Los Jabillos

BRIGING PARTICEL SIZE DATANaricual Inferior and Superior

0.000

0.100

0.200

0.300

0.400

0.500

0.600

0.0010 0.0100 0.1000 1.0000 10.0000 100.0000

BRIDGING PARTICEL DIAMETER

M E R C U R Y S A T U R A T I O N

,

F R A C T I O N ( F R E Q U E N C Y

Ful 7 Sample 8 (NI)

Fu l 46 Sa m pl e 6 (NI )

Ful 46 Sample 2 (NI)

Average

Ful 12 Sample 10 (NS)

Ful 13 Sample 3 (NS)

Fig. 8- Bridging size distribution for Naricual Superior and Inferior


23/32

0.0

0.5

1.0

1.5

2.0

2.5

3.0

3.5

0 20 40 60 80 100 120

Differential Pressure, psi

F l o w

R a

t e ,

m l / m

i Whole Mud Test # 1

Whole Mud Test # 2

Whole Mud Test # 3

Whole Mud Test # 4

Fig. 9- Flow rate versus differential pressure for all the muds tested

Damaged by invasion

Undamaged by invasion

Fig. 10 Examples of the damaged and undamaged thin sections


24/32


25/32

Fig. 13 Pre-Treatment Nodal Analysis Fig. 14 Post-Treatment Nodal Analysis

B e f o r

e

A f t e r

5 M o s .

6 M o s .

0

500

1000

1500

2000

Rate, BOPD

WHP, psi

Figure 15 Flow Rate and Wellhead pressures for FUL 10I


26/32

PARTICLE SIZE DISTRIBUTIONFUL 79 - Base

0

10

20

30

40

50

60

70

80

90

100

0.1 1 10 100 1000

Particle Diameter

C u m u

l a t i v e

< , %

Min Act. Maxd10 1.0 1.77 3.0d50 16.0 20.24 32.0d90 50.0 72.20 99.0

Figure 16 Base Particle Size Distribution

PARTICLE SIZE DISTRIBUTIONFUL 79

0

10

20

30

40

50

60

70

80

90100

0.1 1 10 100 1000

Particle Diameter

C u m u

l a t i v e

< , %

Min Act. Maxd10 1.0 1.77 3.0d50 16.0 20.24 32.0d90 50.0 72.20 99.0

Figure 17 Particle Size Distribution Envelope


27/32

FUL 79Mud Weight, Hydrostatic Pressure, Formation Pressure

10.55

10.60

10.65

10.70

10.75

10.80

10.85

10.90

10.95

11.00

11.0513,300 13,400 13,500 13,600 13,700 13,800 13,900 14,000 14,100 14,200 14,300

M u

d W e i g

h t

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Depth

P r e s s u r e , p s i

Mud Weight Hyd. Pres s. Res ervoir Press ure

Figure 18 Mud and formation Pressure Properties

0.0000

0.0500

0.1000

0.1500

0.2000

0.2500

S p e c

i f i c P r o

d u c

t i v i

t y ,

B O P D / p s

i / f

Well 1 Well 2 FUL-79 Well 4

Figure 19 Comparison of Specific Productivity


28/32


29/32


30/32

Table 4- The Chemical and Physical Properties of the Drilling Muds

COMPANY X DRILLING MUDS

Mud 1: (CaCl 2) Mud 2: (Potasium Formate) Oil Base Mud

Products: Amount: Products: Amount: Composition: Per 350 cc barrel equivalent

CaCl 2 0.9 bbls Iso-Teq 205.4 cc

Brine Density 9.2 ppg Potasium Formate 0.94 bbls Omni-Mul 8.0 cc

MIL-CARB 50 ppb Brine Density 9 ppg 11.0 lb/gal CaCl Brine 88.0 cc

W-306 2 gpb 55 ppb Carbo-Gel 6 gr

Mag-Ox 3 ppb Carbo-Trol 5 gr Milcarb 128 gr

Density,lbm/gal 9.9 Density,lbm/gal 9.82

Rheologies @ F 120 Rheologies @ F 120 Properties:600 rpm 57 600 rpm 45

300 rpm 38 300 rpm 32 Test Temp.- 120 F

200 rpm 32 200 rpm 28 600 rpm rdg 73

100 rpm 23 100 rpm 20 300 rpm rdg 44

6 rpm 9 6 rpm 9 200 rpm rdg 35

3 rpm 7 3 rpm 8 100 rpm rdg 24

Plastic Viscosity, cps 19 Plastic Viscosity, cps 13 6 rpm rdg 11Yield Point, lbf/100 ft2 19 Yield Point, lbf/100 ft2 19 3 rpm rdg 10

Initial Gel,lbf/100 ft2 9 Initial Gel,lbf/100 ft2 9 PV 2910 min Gel,lbf/100 ft2 14 10 min Gel,lbf/100 ft2 15 YP 15

API, mls/30 min 2.8 API, mls/30 min 4.8 Density,lb/gal 9.8Ph 10 Ph 9.4

COMPANY Y DRILLING MUDS

Mud 1: ( NaCl-NaBr) Mud 2: ( Sodium and Potasium Formate) Oil Base Mud

Volume per Lab Volume Volume per Lab Volume

Product Conc.,ppb S.G. barrel ml Product Conc.,ppb S.G. barrel ml Product Conc.,ppb Volume per

ml ml S.G. barrelKCl(5%) 18 2 0.026 9 CaCO 3 C 10 2.8 0.01 3.57 CaCO 3 F 0

CaCO3 C 10 2.8 0.01 3.57 CaCO 3 M 20 2.8 0.02 7.14 CaCO 3 M 20 2.8 0

CaCO3 M 20 2.8 0.02 7.14 CaCO 3 F 10 2.8 0.01 3.57 CaCO 3 C 20 2.8 0.02

CaCO3 F 10 2.8 0.01 3.57 MagOx 1 2.2 0.001 0.45 VG-69 7 2.8 0.02MagOx 1 2.2 0.001 0.45 OS-1L 0.1 1.34 0 0.07 V.Mod 1 1.57 0.013

OS-1L 0.1 1.34 0 0.07 Blended 3 1.56 0.005 1.92 V.Coat 2 0.98 0.003

Blended 5 1.56 0.009 3.21 Product A mount V.Mul 6 0.968 0.006Product Amount Lime 6 0.9 0.019

Fresh water 0.846 bbl/bbl 66% Sodium Formate 10.5 ppg Barite 176.72 2.2 0.008

100% NaCl 55.0 ppb 34% Potasium Formate 13.18 ppg 4.2 0.1295% NaBr 126.0 ppb Product Amount,for liquid fraction

Oil 159.32 gms

Water 79.94 gmsCaCl 2 27.02 gms


31/32

Table 5- Company X Permeability Evaluation of the Mud System

Core Sample Return perm.(%)(Depth) Overbalanc e, ps i Initial Perm. Initial- Fina lFul 7 Sa mple3 820 193 112md-164md(85)(14227.6)Ful 12 Sample6 690 36.1 12.6-24.6md(68)

(149866)Ful46 Sample14 840 15.36 8.93-14.6(95)(15265.4)

Table 6- Summary of Leakoff/Return permeability

Net Confining Stress: 4750 psi Temperature: 300FCirculati on Temperature: 300F Overbalance: 600 psi

Mud Information ReturnTotal Terminal Permeability, Terminal

Spurt Leakoff Leakoff percent W ater

Loss, Volume, Rate, Saturation,milliliters milliliters cm/min fraction

Composi te 1 - Company X CaCl 2 Mud (Water-Based)Injection

7 FUL-12 131 0.149 0.095 0.33 26.8 0.013 25.0 1.6 10.9 14.5 0.3004 FUL-53 107 0.142 0.121 0.345Production

Composite 2 - Company Y Na/KHCO 2 Mud (Water-Based)

Injection6 FUL-53 70.9 0.135 0.119 0.98 34.7 0.0058 17.0 4.9 16.3 25.2 0.2855 FUL-53 84.8 0.141 0.111 0.294Production

Composite 3 - Company Y (Oil-Based)

Injection3 FUL-2 166 0.144 0.110 0.28 4.80 0.0015 1.0 23.0 83.0 90.9 0.1243 FUL-13 260 0.164 0.093 0.130Production

Composite 4 - Company X (Oil-Based)

Injection4 FUL-46 163 0.131 0.22 4.79 0.00067 11.0 5.5 78.7 92.42 FUL-46 182 0.155Production

SampleNumber Well

Klinkenberg

Permeability,millidarcies

Porosity,fraction

Initial Water

Saturation,fraction

Break

Pressure,psi

I-0.5" 0.5-1.5" 1.5"-P

Table 7 - The depth of invasion of drilling muds

Company Company X Company X Co mpany Y Co mpany YMud Filtrate CaCl2 Oil Based Na/KHCO2 Oil BasedSample ID FUL-12 Samp le7 FUL-46 Sample4 FUL-53 Sample6 FUL-2 Sample 3Max. Solid InvasionDepth 3.2 mm 1.3 mm None 0.6 mmInvasion Depth of 95% of Solids 0.7 mm 0.1 mm Thin Coating 0.1mm


32/32

Table 8- Initial Mud Formulation

Diesel 70% by vo lumeW ater 30% by vo lumeCaCl2 27.02 ppbRheology agent 7.00 ppbLime 6.00 ppb

Suspending agent 1.00 ppbW etting agent 2.00 ppbEmulsifier 6.00 ppbCaCO 3 Mediu m 20.00 ppbCaCO 3 Course 20.00 ppbBarite 176.72 ppb

Table 9 Summary of Mud checks

FUL-79 MUD CHECKS

Date DepthMud Weight

11-10Viscosity

30-35Solids 18-

28%Salinity250,000

Water loss

Documents

Paper 54722 - Insol Pdvsa