jot winter2014

Spring 2014

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGYA quarterly publication of the Saudi Arabian Oil CompanyJournal of Technology

Saudi Aramco

Saudi A

ramco Jo

urnal o

f Technology Sp

ring 2014

Limited Entry, Multiple Injection Matrix Acidizing Technology Boosts WellProduction in the Worlds Fourth Largest Gas Reservessee page 2

Development of Mature Fields Using the Reservoir Opportunity Index: ACase Study from a Saudi Fieldsee page 37

67840araD1R1_67840araD1R1 3/4/14 2:27 PM Page 1

Gelled Emulsion of CO2 Water NanoparticlesFawaz M. Al-Otaibi, Yun C. Chang, Dr. Sunil L. Kokal, Jassi F. Al-Qahtani and Amin M. Al-Abdulwahab

ABSTRACT

Enhanced oil recovery (EOR) by carbon dioxide (CO2) injection is quickly becoming an important and effective method forrecovering additional oil beyond waterflooding. The CO2 EOR process is handicapped, especially in thick reservoirs, by CO2gravity override. Due to density differences between the injected CO2 and resident fluids in the reservoir, the CO2, being lighter,tends to rise to the top of the reservoir, thereby bypassing some of the remaining oil. Different techniques have been used toovercome the CO2 gravity override by either increasing its density and viscosity, or by reducing its relative permeability.

Calibrating Log Derived Stress Profiles in Anisotropic Shale Gas FormationsAnas M. Al-Marzooq, Hussain A. Aljeshi and Abdullah Al-Akeely

ABSTRACT

The complex properties of unconventional gas resources pose challenges to petrophysical evaluation techniques and tools. Datafrom standard logging tools and standard interpretation techniques produce high levels of uncertainties in the analysis, therebylimiting their reliability in producing thorough petrophysical solutions. Both tight gas and shale gas formations add multiplelayers of complexity to the petrophysical evaluation, with their complex lithology and heterogeneity causing uncertainty in thehydrocarbon volume calculations and hydraulic fracturing completion designs.

Overcoming Hydraulic Fracturing Challenges in High Temperature and Tight Gas Reservoirs of Saudi Arabia with anEnhanced Fracturing Fluids SystemSaad M. Al-Driweesh, Alaa A. Dashash, Ataur R. Malik, Jairo A. Leal Jauregui, Eduardo Soriano and Alfredo Lopez

ABSTRACT

Hydraulic fracturing has been an important aspect of the successful exploitation of gas sandstone formations in Saudi Arabia.During the past decade, conventional formations were stimulated successfully with traditional, low to moderate temperature,borate cross-linked fracturing fluids. As the development of the existing fields continues into deeper formations and explorationactivities are inclined toward unconventional reservoirs, new challenges are experienced due to the lower permeabilities andhigher temperatures. The conventional borate cross-linked gels are no longer the choice of fracturing fluids for extreme bottom-hole conditions.

Real Life Natural Fracture Detection Examples and Workflows for Implementing Fractures in Simulation ModelsStig Lyngra, Dr. Constantine Tsingas and Nazih F. Najjar

ABSTRACT

Systematic fracture characterization is required to construct a well-constrained static and dynamic fracture model of thereservoir. The main challenge is the need to integrate all the available data sets in a consistent manner, ranging in scale from coresamples to seismic, to allow construction of appropriate detailed geologic models and up-scaled simulation models. If this isdone with sufficient understanding of the geology and dynamic behavior of the reservoir, a history match to all available fielddynamic data can be performed. The history matched simulation model is used to generate prediction scenarios of future oil andwater production.

On the Cover

A stage of the limited entry, multiple injection matrix acidizing

technology, as designed by the Ghawar gas production engineering

team at Saudi Aramco. The stage was specifically customized to

address the special needs of the candidate well.

This technology effectively places the designed treatment at an

optimal rate and pressure along the stage length, maximizing the

development of complex conductive flow channels, also known as

wormholes, throughout the entire stimulated reservoir length.

The green color signifies the stimulation treatment fluids and their

uniform distribution across the rock matrix of the target zones of the

formation.

It was necessary to develop this tool to address the more prolific

zones of the Khuff-C formation, where efficient matrix acidizing was

sought as an alternative to acid fracturing.

Mohammed A. Al-Ghazal, a Saudi Aramco engineer, runs a high-profile acidizing operation using high-pressure/high temperature(HP/HT) equipment to enhance the deliverability of a deep, deviatedgas producer.

The Saudi Aramco Journal of Technology ispublished quarterly by the Saudi Arabian OilCompany, Dhahran, Saudi Arabia, to providethe companys scientific and engineeringcommunities a forum for the exchange ofideas through the presentation of technicalinformation aimed at advancing knowledgein the hydrocarbon industry.

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EDITORIAL ADVISORS

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Charles T. KresgeExecutive Director, Chief Technology Officer

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EDITORIAL ADVISORS (CONTINUED)

Sami A. Al-KhursaniProgram Director, Technology

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CONTRIBUTIONS

Relevant articles are welcome. Submissionguidelines are printed on the last page.Please address all manuscript and editorial correspondence to:

EDITOR

William E. BradshawThe Saudi Aramco Journal of TechnologyC-86, Wing D, Building 9156Dhahran 31311, Saudi ArabiaTel: +966-013-876-0498E-mail: [email protected]

Unsolicited articles will be returned onlywhen accompanied by a self-addressedenvelope.

Khalid A. Al-FalihPresident & CEO, Saudi Aramco

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Spring 2014

THE SAUDI ARAMCO JOURNAL OF TECHNOLOGYA quarterly publication of the Saudi Arabian Oil CompanyJournal of Technology

Saudi Aramco

Contents

Limited Entry, Multiple Injection Matrix Acidizing Technology Boosts Well Production in the Worlds Fourth Largest Gas Reserves 2Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Mustafa R. Al-Zaidand Fadel A. Al-Ghurairi

A New Real-Time Analysis Method for Pressure Tests in Low Permeability Reservoirs 10Mohammed F. Al-Zayer, Amer H. AbuHassoun, Dr. Sami Eyuboglu, Amir Anwar, Nacer Guergueb and Mark Proett

Improved Reservoir Surveillance through Injected Tracers in a Saudi Arabian Oil Field: Case Study 16Muhanad A. Al-Mosa, Husain A. Zaberi and Dr. Olaf Huseby

Quantifying the Intelligent Field Added Values 29Zaki B. Husain and Muhammad A. Al-Hajri

Development of Mature Fields Using the Reservoir Opportunity Index: A Case Study from a Saudi Field 37Alfonso Varela-Pineda, Dr. Ahmed H. Alhutheli and Dr. Saad M. Al-Mutairi

Comprehensive Reservoir Vertical Interference Testing to Optimize Horizontal Well Placement Strategy in a Giant Carbonate Field 44Mabkhout A. Al-Harthi, Cesar H. Pardo, Khaled A. Kilany, Majid H. Al-Otaibi, Dr. Murat M. Zeybek and Asif Amin

Quantifying Gas Saturation with Pulsed Neutron Logging An Innovative Approach 53Mamdouh N. Al-Nasser, Dr. Shouxiang M. (Mark) Ma, Nedhal M. Al-Mushrafi, Ahmed S. Al-Muthana, Steve W. Riley andAbel I. Geevarghese

Insight into SmartWater Recovery Mechanism through Detailed History Matching of Coreflood Experiments 60Dr. Abdulkareem M. AlSofi and Dr. Ali A. Yousef


Prinect PDF ReportDocument contains a Prinect PDF ReportSee Document -> File Attachements...

ABSTRACT stress component and calibrating the stress profiles against ac-tual open hole logs became the most important highlights of thenew workflow. Radical improvement of stage integrity, multiplefracture signatures and enhanced well productivity were amongthe most important results achieved in developing the deep,tight gas-bearing zones of the Khuff carbonate reservoir.

Still, an innovative approach was required to address themore prolific zones of the Khuff-C formation where efficientmatrix acidizing was sought as an alternative to acid fracturingin wells that could only be drilled in the max direction. There-fore, a purpose built open hole multistage technology system one that was developed around the idea of distributed limitedentry for placement of matrix acidizing treatments was iden-tified and carefully evaluated.

This article presents the details of the successful applicationof this new limited entry, multiple injection technology for opti-mized matrix acidizing of carbonate horizontal wells, includingtrial testing qualification, candidate selection, system design,functionality, operation and ultimate production profiling.

INTRODUCTION

Tight gas, low permeability reservoirs present a tremendouschallenge with respect to effectively completing and draining a target reservoir. Cased hole and open hole completions inhorizontal wells offer a cost-effective means of accessing theentire lateral section, assuming the target pay can be effectivelystimulated. While most open hole completions possess moreadvantages than cased hole completions, the challenge withopen hole completions, compared to more conventional cased,cemented and perforated completions, is understanding andcontrolling the fracturing fluid flow into the near wellbore areaof the reservoir.

The Khuff reservoir development has offered opportunitiesfor a wide array of completion techniques to be implemented andevaluated, ranging from single stage vertical wells through mul-tilateral wells to multistage horizontal wells. As the focus grad-ually shifted to tighter parts of the reservoir, the well completionsunderwent a process of increased complexity, from verticals tomultilaterals and finally to horizontal multistage fracturingcompletions, which are also gaining popularity at the worldscale as the industry taps more unconventional resources.

Acid fracturing or matrix acidizing is often required for increasedhydrocarbon production and long-term well deliverability fromthe massive Khuff carbonate gas reservoir in Saudi Arabia, theholder of the worlds fourth largest gas reserves. Open holemultistage technologies have demonstrated superior perform-ance in maximizing reservoir contact and productivity throughbetter distribution of acid across the formation matrix, full in-terval matrix contribution and efficient propagation of fracturenetworks to bypass formation damage and optimize near well-bore conductivity.

The Khuff structure is a late Permian age heterogeneous car-bonate sequence that underlies the massive Ghawar field in theEastern Province of Saudi Arabia. The Khuff reservoir is subdi-vided into four separate intervals (A through D), with productioncoming mainly from the B and C intervals. Since its initial ap-praisal in the late 1970s, the majority of Khuff development hasbeen focused in the relatively more prolific Khuff-C formation,where coiled tubing acid wash and single-stage acid treatmentswere repeatedly performed and evaluated. Over the past fiveyears, multistage acid fracturing has been implemented in SaudiArabias Khuff-C development. The results were carefully eval-uated for each trial, and this is now the predominant Khuff-Cstimulation technique.

Up until the middle of 2011, the vast majority of Saudi Ara-bias horizontal Khuff carbonate gas wells were drilled alongthe direction of maximum horizontal in situ stress (max). Thiswas primarily to enhance wellbore stability and achieve the bestpossible penetration rates. Early multistage fracturing treat-ments in the Khuff generated mostly longitudinal fracturespropagating parallel to the wellbore or in the max direction.Since then, a holistic approach toward the application of openhole multistage technology for tight reservoir development hasbeen adopted.

The complex workflow of this approach calls for, amongother requirements, changing the lateral section placementstrategy and planning the horizontal section to be drilled alongthe minimum horizontal in situ stress (min) direction as opposedto the previous mode of planning along the max direction. Ac-cordingly, understanding the reservoir stress profile, orientingthe horizontal wellbore with respect to the dominant horizontal

Limited Entry, Multiple Injection MatrixAcidizing Technology Boosts WellProduction in the Worlds Fourth LargestGas ReservesAuthors: Mohammed A. Al-Ghazal, Saad M. Al-Driweesh, Mustafa R. Al-Zaid and Fadel A. Al-Ghurairi

2 SPRING 2014 SAUDI ARAMCO JOURNAL OF TECHNOLOGY


Early applications of open hole multistage completion tech-nology in Saudi Arabia started in 2007 when the specified numberof stages were run with a typical configuration of a single frac-turing port between each two mechanical open hole isolationpackers1-5. Acid fracturing was conducted in the multiple stagesthrough selective activation of the fracturing ports. It was observedthat in wells drilled in the maximum horizontal in situ stress(max) direction, the first stage fracture will grow longitudinally,along the wellbore, parallel to max, causing the potential riskof overlap with subsequent induced fractures due to naturalfractures and formation fissures. Initiation of the second andthird fractures therefore became a challenge, due to possiblepressure communication across the first induced fracture. Toavoid this fracture overlap, it was decided that wells needed tobe drilled in the minimum horizontal in situ stress (min) direc-tion, allowing transverse fracture initiation perpendicular to thewellbore. The results from wells with open hole multistagecompletions showed increased initial production and less depar-ture from the theoretical hyperbolic decline curves6.

For wells designated for matrix acidizing stimulation, an issuerose regarding the ability of the single fracture port per stage toachieve uniform and effective stimulation of the entire stagelength. To maximize the stimulated reservoir volume and reducethe likelihood of localized treatment of more prolific sections, itwas necessary to think of a better way to address the specificneeds for ensuring efficient stimulation and guaranteeing ho-mogeneous distribution of the acid treatment across the stagelength. This article discusses the first successful application ofan innovative matrix acidizing technology in the more prolificzones of the Kuff carbonate gas reservoir.

TRIAL TESTING QUALIFICATION

There is often debate regarding the best approach for completingtight gas, low permeability reservoirs. This debate stems fromthe fact that tight gas reservoirs are more challenging to developthan traditional gas reservoirs and are relatively new in the industry due to previously existing technology and economic restrictions. One such debate involves the viability of the openhole packers with the fracture sleeves completion method to ef-fectively stimulate long horizontal intervals of a targeted tightgas formation. The argument in favor of this completion ap-proach is that a large area between the packers is exposed tothe treatment fluid, providing the opportunity to create multiplefracture initiation points for the fracturing fluid and proppantto enter the target formation. This approach also has the ad-vantage of being minimally influenced by near wellbore fluidfriction constraints, such as perforation friction and/or perfora-tion tunnel induced tortuosity, because the production casing orliner is not cemented. It is worth mentioning here that attempt-ing to verify actual points of fracturing fluid entry and howmany points of entry exist without advanced diagnostics ischallenging, and fluid entry cannot effectively be modeled withconventional fracture modeling approaches.

The Permian Khuff-C carbonate formation is generally aprolific, nonassociated gas and condensate producing memberof the giant Khuff reservoir in the Ghawar structure of SaudiArabia. Extensive heterogeneity in stress profile, reservoir qualityand reservoir fluids throughout the field, combined with the deepand extremely hot nature of the reservoir, makes uniform andeffective stimulation of all layers a challenging task7, 8. In thisregion, acid stimulation is required in the form of either matrixacidizing or acid fracturing to obtain high production rates andto add tie-in wells to the production facilities, all to meet theever-growing demand for natural gas products. Matrix acidizingallows the removal of near wellbore damage induced during thedrilling phase, while acid fracturing opens up channels beyondthe near wellbore; both improve well productivity.

In matrix acidizing of prolific carbonate reservoirs, accurateacid placement is a major challenge as the acid tends to flow pref-erentially towards the highest permeability zones of the targetinterval (negative pressure effect), further increasing local per-meability at these intervals and leaving the lower permeabilityregions of the formation untapped and untreated. To select thepacker setting depths so that the packers are placed in competentformations and to refine the fracture stage interval lengths to tar-get discrete pay intervals, the wells local structure information andopen hole log data should be carefully analyzed and reviewed.

In most cases, the open hole multistage tool layout is designedwith uniform interval spacing. The spacing of packers and frac-ture sleeves is typically identical from stage to stage, with littleregard to local geology and potential production units. For thedesign of this trial, the local structure information and open holelog data were used to position the packer setting depths so pack-ers were in competent formations and to refine the fracture stageinterval lengths and sizes to target discrete pay intervals. Theintent of placing packers with varied spacing was to isolatefracture intervals with a similar log signature, which possiblyindicates specific hydraulic flow units and discrete intervalswith a propensity for production. This allowed the number offracture intervals and stages, as well as the overall completioncosts, to be optimized. Stimulation designs were prepared andtailored for each of the individual intervals.

It is also important to note that in this trial the geomechanicalproperties of the formation were predisposed to creating or tap-ping into a natural fracture network. Consequently, the formationhad the potential to create a well-connected simulated reservoirvolume, as opposed to discrete planar-type transverse hydraulicfractures. Therefore, a further goal of this particular trial test wasto integrate that geomechanical information with the treatmentdata and the fully processed open hole logs. This resulted in morerobust conclusions and recommendations for improving stimu-lation effectiveness when using this particular completion strategy.

LIMITED ENTRY, MULTIPLE INJECTION MATRIX ACIDIZING TECHNOLOGY OVERVIEW

The limited entry, multiple injection matrix acidizing assembly

SAUDI ARAMCO JOURNAL OF TECHNOLOGY SPRING 2014 3


is best suited for matrix acid treatments in prolific and natu-rally fractured carbonate formations. Unlike standard open holemultistage completion systems9-12, where there is only onefracture port per stage, the limited entry system features multi-ple jet nozzles placed in a single interval to create a strong ma-trix acidizing effect throughout the entire open hole interval13,Fig. 1.

Stages are created using multiple shear-activated stimulationjets that are spaced out in the sections of interest and isolatedby hydraulically set mechanical open hole packers, Fig. 2. Thejet nozzles are adjusted and placed according to the reservoircharacteristics determined from open hole logs, enabling con-trolled injection and leak off for effective flow of the acid treat-ment into the entire section of the interval. This effectivelyplaces the designed treatment at an optimal rate and pressurealong the stage length, maximizing the development of complexconductive flow channels, also known as wormholes, through-out the entire stimulated reservoir length.

Each stage consists of a drillable cutter assembly pinned intoa shear housing assembly. Downhole of the shear housing areshear-activated stimulation jet assemblies, spaced out with cas-ing/liner at predetermined depths. Above the lowermost packerin each stage is the locking/landing sub. The locking/landingsub provides isolation of this stage from lower stages and locksthe drillable cutter to prevent it from rotating during millingoperations. For effective setup of the system in the reservoirsection, the liner and the annulus are isolated.

The liner isolation is achieved by the activation balls as theyland on their respective seats in the cutter assembly, closing offthe stages below. Multiple stages can be run, starting with thesmallest activation ball and ending with the biggest ball size at thetop. This mechanical diversion, combined with an advancedchemical diversion system, allows uniform, precise fluid placement.

Isolation of the annulus is achieved using open hole packers.The criteria for selecting a packer is to identify which packer

will ensure efficient annular isolation between stages, cope withtemperature cooling effects or the shrinkage phenomenon ascooler treatment fluids are pumped from the surface, and with-stand high differential pressure cycles during fracturing so as tomaintain the stability and pressure integrity of the completionsystem. Hydraulically set, mechanical, dual-element open holepackers are designed to withstand high differential pressures(up to 10,000 psi) during treatment cycles at reservoir tempera-ture, Fig. 3a. Such dual-element packers provide the long-termisolation required to separate adjacent fractured intervals and sohelp ensure independent fracture propagation. These packers areequipped with a dynamic setting mechanism, which uses the elevated treatment pressures to continuously deliver additionalpack off forces to the elements as the treatment pressures increaseover the initial setting pressure inside the liner a criterionthat allows the packer to cope with the sudden downhole tem-perature decrease as colder treatment fluids are pumped fromthe surface14.

Swellable packers, sometimes referred to as swellable ele-ment packers and/or reactive element packers, with swellingelastomer systems can also be combined with this assembly, yetthey will remain passive, making no response to the dynamictemperature changes during pumping, Fig. 3b. Depending onthe type of packer element, the design temperature and wellborefluids, the elastomers can swell when exposed to the formationshydrocarbon or water.

In a limited entry, multiple injection matrix acidizing system,as acid is pumped from the surface, it is distributed evenlythrough the jets, where it interacts with the formation directlyin front of the nozzles, Fig. 4. Therefore, it is prudent to placethe jets in front of the sections that need to be treated first. Theother sections of the reservoir will be treated as more and more

Fig. 1. Limited entry, multiple injection matrix acidizing technology utilizesmultiple jet nozzles to achieve complete matrix interval contribution.

Fig. 2. Shear-activated stimulation jets and packers in the limited entry, multipleinjection matrix acidizing system; open hole log data are used to position thepackers and refine the fracture stage interval lengths.

Fig. 3a. Hydraulically set, mechanical, dual-element open hole packer.Fig. 3b. Swellable packer.

Fig. 4. Acid stimulation through a limited entry, multiple injection matrix acidizingsystem for effective wormhole creation.

Fig. 5a. First stage treatment from a single port at the bottom.Fig. 5b. Second and third stage treatments through multiple stimulation jets.



acid is dispensed and spread along the wellbore in the openhole section.

CANDIDATE WELL

The candidate well, Well-A, was a flank well drilled parallel tothe max direction. After analysis of the open hole log, a three-stage limited entry, multiple injection matrix acidizing systemwas specified with a hydraulic fracture port for the first stageand six limited entry stimulation jets for each of the secondand third stages, Figs. 5a and 5b. The system was successfullydeployed to total depth in the 4,000 ft thick gross pay, andmatrix acidizing was pumped as per schedule for the threestages. As shown in Fig. 6, the opening and closing of each in-terval and the pumping of the acid treatment went as per de-sign without any operational issues. Table 1 presents some ofthe main treatment parameters15.

Figure 7 presents the wellbore layouts as well as the stressand porosity profiles of Well-A and three offset wells in theKhuff reservoir. The three offset wells Well-B, Well-C andWell-D are dual-lateral, deviated and vertical wells, respec-tively. The candidate well, Well-A, has a 1,300 ft net reservoircontact, laterally drilled in the max direction. Table 2 presentssome of the reservoir and well characteristics as well as stimula-tion parameters for all wells. Each of the wells has been drilledand stimulated with different techniques; however, the reservoirflow capacity and permeability thickness product (kh) of thewells are comparable.

PRODUCTION DATA ANALYSIS

Open hole multistage technology has been implemented in var-ious fields across Ghawar field to enhance productivity frommoderate to tight reservoirs and to assess the technical andeconomic feasibility of this enabling technology in each fieldand each reservoir. Figure 8a highlights the distribution ofopen hole multistage technology applications in various deep

Fig. 6. Pumping pressure and rate chart for the Well-A acid treatment.

Stage-1 Stage-2 Stage-3

Max. Pressure (psi) 8,022 8,910 8,210

Max. Rate (bpm) 35 39 41

Avg. Rate (bpm) 23 30 30

Table 1. Limited entry treatment parameters for Well-A

Fig. 7. Bottom-hole location and trajectory of Well-A and the three offset wells inthe Khuff reservoir.

Well Name Well Type Treatment TypeReservoir Net

Height (Reservoir Contact) ft

khmd-ft

Number of Stages

Average Pump Rate (bbl/min)

Acid Volume(kgal)

Well-A Horizontal Open Hole

Limited Entry, Multiple Injec-

tion Matrix Acidizing

70 (1,300) 55 3 25 125

Well-B2 LateralsHorizontal Open Hole

Coiled Tubing Matrix 70 (1,550) 60 1 5 126

Well-C 60 Cased Hole Perforation

Acid Fracturing + Diverter 70 55 1 34 45

Well-DVertical Cased

Hole Perforation

Acid Fracturing 65 60 1 34 65

Table 2. Pumping and reservoir parameters for candidate Well-A and its offset wells



gas development fields in Saudi Arabia. This spans carbonateand clastic reservoirs, and the treatments include both acid andproppant fracturing.

Figure 8b illustrates the sustained gas rate achieved fromthese different fields by applying open hole multistage technology.The total number of stages included in the evaluation is about120. The number of fracture stages and the amount of acid orproppant pumped are dependent on reservoir properties anddevelopment. For the reservoirs that are currently being devel-oped, five to eight treatment stages provide excellent coverageand production rates.

Most wells went through successful stimulation treatmentsas per design. The wells were subsequently cleaned up, flowedback, tested to confirm economic gas production rate and flowing

pressure, and put on production. Figure 9 presents the normal-ized productivity index (PI) for the candidate Well-A and thethree offset wells, showing the higher gas contribution fromWell-A.

With the appropriate selection of candidate wells, treatmentswith both open hole multistage fracturing and limited entry, multi-ple injection matrix acidizing completions showed successful results, and each method contributed to high well productivity.Figure 10a presents the fold increase in well PI from the applica-tion of multistage fracturing over single-stage vertical fracturetreatments. Figure 10b presents acidizing treatments where theapplication of limited entry, multiple injection matrix acidizinghas superseded the standard multistage matrix acidizing.

CONCLUSIONS

The following conclusions are drawn from the work per-formed in the Khuff reservoir:

1. For this operation, the limited entry, multiple injectionmatrix acidizing technology components of stages 2 and 3functioned successfully, as demonstrated by the pressuresignatures of launching the cutter assemblies of these stagesfrom the shear housings upon dropping the respectiveactivation balls.

2. The limited entry, multiple injection matrix acidizingtechnology activation balls must be chased down the fracstring with much higher pumping rates 25 bbl/min to35 bbl/min as compared to the normal open holemultistage fracturing balls 5 bbl/min to 7 bbl/min.The resultant higher fluid momentum creates a complex

Fig. 8b. Sustained post-multistage fracturing well production rates showingimproved productivity.

Fig. 8a. Distribution of open hole multistage stimulation technology applicationsin the deep gas development program in Saudi Arabia.

Fig. 9. Normalized PI comparison between Well-A and three offset wells.

Fig. 10b. Fold increase in PI of limited entry, multiple injection matrix acidizingover standard matrix acidizing.

Fig. 10a. Fold increase in PI between conventional and open hole multistagecompleted wells.



downhole hydraulic scenario, which usually alters theshape and profile of the pressure signatures on thepumping plot. This may not allow the various cutterreleasing and landing steps to be captured on the plotand/or may actually translate into pressure responses onthe surface.

3. The limited entry, multiple injection matrix acidizingtechnique:

Evenly distributes the treatment across the interval by diverting acid to the entire isolated section of the open hole.

Is a superior quality treatment over the conventional bullheading or coiled tubing acidizing.

Is readily applicable to wells that have moderate to good reservoir permeability with reservoir heterogeneity and that require near wellbore stimulation and optimal acid dispersion along the treated interval.

Is not a replacement for traditional multistage fracturing where discrete fractures and deep penetration are required, particularly in the moderate to tight gas reservoirs.

4. Both open hole multistage fracturing completion systemsand the limited entry, multiple injection matrix acidizingtechnique have been successful in their own areas ofapplication and have proven benefits when the properwell candidates are selected and treatment assemblies aresuccessfully deployed.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco for their permission to publish this article. Also, specialthanks go to the stimulation team at Saudi Aramco. Further-more, the authors would like to express a very warm and sincereappreciation to Wael El-Mofty of Packers Plus Energy Servicesfor providing valuable information with regard to the technologydevelopment and design. In addition, the authors are verythankful for the field operational crew and their continueddedication.

The authors would also like to extend special recognition toProfessor George V. Chilingar for his significant contributionsin advancing the knowledge about carbonate rocks.

This article was presented at the SPE Kuwait Oil and GasShow and Conference, Mishref, Kuwait, October 7-10, 2013.

NOMENCLATUREmax maximum horizontal in situ stressmin minimum horizontal in situ stresskh permeability-thickness product, md-ft

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9. Ahmed, M., Rahim, Z., Al-Anazi, H., Al-Kanaan, A.A. andMohiuddin, M.: Development of Low PermeabilityReservoir Utilizing Multistage Fracture Completion in theMinimum Stress Direction, SPE paper 160848, presentedat the SPE Saudi Arabia Section Technical Symposium andExhibition, al-Khobar, Saudi Arabia, April 8-11, 2012.



10. Al-Jubran, H.H., Wilson, S. and Johnston, B.: Successful Deployment of Multistage Fracturing Systems in Multilayered Tight Gas Carbonate Formations in Saudi Arabia, SPE paper 130894, presented at the SPE Deep Gas Conference and Exhibition, Manama, Bahrain, January 24-26, 2010.

11. Rahim, Z., Al-Kanaan, A.A., Johnston, B., Wilson, S., Al-Anazi, H. and Kalinin, D.: Success Criteria for Multistage Fracturing of Tight Gas in Saudi Arabia, SPE paper 149064, presented at the SPE/DGS Saudi Arabia Section Technical Symposium and Exhibition, al-Khobar, Saudi Arabia, May 15-18, 2011.

12. Seale, R.: An Efficient Horizontal Open Hole Multistage Fracturing and Completion System, SPE paper 108712, presented at the International Oil Conference and Exhibition, Veracruz, Mexico, June 27-30, 2007.

13. Baumgarten, D. and Bobrosky, D.: Multistage Acid Stimulation Improves Production Values in Carbonate Formations in Western Canada, SPE paper 126058, presented at the SPE Saudi Arabia Section Technical Symposium, al-Khobar, Saudi Arabia, May 9-11, 2009.

14. Rivenbark, M. and Dickenson, R.: New Open Hole Technology Unlocks Unconventional Oil and Gas ReservesWorldwide, SPE paper 147927, presented at the SPE AsiaPacific Oil and Gas Conference and Exhibition, Jakarta, Indonesia, September 20-22, 2011.

15. Al-Ghazal, M.A.: First Successful Deployment of Rapid STIM Technology, Saudi Aramco Ghawar Gas Production Engineering Division Internal Documentation, November 2012.

BIOGRAPHIES

Mohammed A. Al-Ghazal is aProduction Engineer at Saudi Aramco.He is part of a team that is responsiblefor gas production optimization in theSouthern Area gas reserves of SaudiArabia. During Mohammeds careerwith Saudi Aramco, he has led and

addressing pressure control valve optimization, cathodicprotection system performance, venturi meter calibration,new stimulation technologies, innovative wirelinetechnology applications, upgrading of fracturing strategies,petroleum computer-based applications enhancement andsafety management processes development.

In 2011, Mohammed assumed the position of GasProduction HSE Advisor in addition to his productionengineering duties. He founded the People-Oriented HSEculture, which has brought impressive benefits to SaudiArabia gas fields and resulted in improved operationalperformance.

In early 2012, Mohammed went on assignment with theSouthern Area Well Completion Operations Department,where he worked as a foreman leading a well completionsite in a remote area.

As a Production Engineer, Mohammed played a criticalrole in the first successful application of several high-endtechnologies in the Kingdoms gas reservoirs. Mohammedsareas of interest include formation damage investigationand mitigation, coiled tubing applications, wirelineoperations, matrix acidizing, hydraulic fracturing andorganizational HSE performance.

In 2010, Mohammed received his B.S. degree withhonors in Petroleum Engineering from King FahdUniversity of Petroleum and Minerals (KFUPM), Dhahran,Saudi Arabia.

He has also authored and coauthored several Society ofPetroleum Engineers (SPE) papers and technical journalarticles as well as numerous in-house technical reports.Additionally, Mohammed served as a member of theindustry and student advisory board in the PetroleumEngineering Department of KFUPM from 2009 to 2011.

As an active SPE member, he serves on the Productionand Operations Award Committee.

Recently, he won the best presentation award at theproduction engineering session of the 2013 SPE YoungProfessional Technical Symposium.

Mohammed is currently pursuing an M.S. degree inEngineering at the University of Southern California, LosAngeles, CA.



participated in several upstream projects, including those

Saad M. Al-Driweesh is a GeneralSupervisor in the Southern AreaProduction Engineering Department(SAPED), where he is involved in gasproduction engineering, wellcompletion, and fracturing andstimulation activities.

Engineers (SPE), where he has chaired several technicalsessions in local, regional and international conferences. He is also the 2013 recipient of the SPE Production andOperations Award for the Middle East, North Africa andIndia region. In addition, Saad chaired the firstUnconventional Gas Technical Event and Exhibition inSaudi Arabia.

He has published several technical articles addressinginnovation in science and technology. Saads main interestis in the field of production engineering, includingproduction optimization, fracturing and stimulation, andnew well completion applications. He has 26 years ofexperience in areas related to gas and oil productionengineering.

In 1988, he received his B.S. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.

Mustafa R. Al-Zaid is a GasProduction Engineer at Saudi Aramcoworking for the Southern AreaProduction Engineering Department(SAPED).

In 2010, he received his B.S. degreein Petroleum Engineering from the

Fadel A. Al-Ghurairi is a PetroleumEngineering Consultant and TechnicalSupport Unit Supervisor working ongas fields. He has 24 years ofexperience in production and reservoirengineering. In the last 12 years, Fadelhas specialized in stimulation and

In 1988, he received his B.S. degree in PetroleumEngineering from King Fahd University of Petroleum andMinerals (KFUPM), Dhahran, Saudi Arabia.



Saad is an active member of the Society of Petroleum

University of Adelaide, Adelaide, Australia.

fracturing of deep gas wells.

ABSTRACT of the tools. The primary concern relates to how FTWD pres-sure measurements compare to wireline measurements, and asbefore, their reliability for formation evaluation. FTWD toolsare of interest because they can perform measurements muchsooner during the life of a well and in a potentially more dynamic environment1.

Formation pressure measurements taken while drilling canbe affected by supercharging, which is defined as the in-creased pressure observed at the wellbore sandface2. Withoutproper correction, supercharging can distort the pressurereadings, particularly in low permeability formations.

Pressure variations near the wellbore are primarily influ-enced by mud filtrate invasion and mud cake formation1. Con-siderable progress has been made toward understanding howmud cakes form and influence near-wellbore pressure stability3-5.Based on that research, miscible and immiscible multiphasesimulators have been developed to predict the filtrate invasionfor oil-based mud (OBM) and water-based mud (WBM)6. As aresult of research performed6, it is possible to make simplifyingassumptions about well conditions and still obtain a reasonableestimate of near-wellbore pressures, although in reality thenear-wellbore is a complex environment. To control the pro-duction of formation fluids into the wellbore, wellbore pressureis normally maintained at a pressure substantially greater thanthe formation pore pressure. The wellbore sandface is exposedto hydrostatic pressure, and the filtrate immediately invadesthe near-wellbore region when a producing zone is penetrated.Mud cake is formed when drilling fluid flows into the forma-tion and solids are deposited on the surface of the wellbore.This process is normally referred to as static filtration. As themud cake grows, it eventually stabilizes at a maximum thick-ness. Stabilization is a result of the shearing action of the mudcirculation in the annulus as well as the mechanical action ofthe rotating drillpipe. This process is referred to as dynamic fil-tration. During these processes, a pressure gradient is estab-lished in the formation, Fig. 1. The pressure in the wellborenear the surface of the mud cake is at hydrostatic (Pmh) levels,but drops rapidly across the mud cake, and then gradually de-creases across the formation, approaching formation pressure(Pf) some distance from the wellbore. The supercharge pres-sure (Psc) can be defined as the difference between sandfacepressure (Pss) and Pf.

Formation testing while drilling (FTWD) tools were introducedas alternatives to wireline testing almost a decade ago. Interpre-tation of pressure tests conducted during drilling of horizontalsections, however, is difficult because of the dynamic environ-ment and unsteady hydrostatic pressure. One major challengerelated to pressure measurement while drilling is supercharging,which is an increase of sandface pressure above the true reservoirpressure. This is caused by mud filtrate invasion. The sandfacesupercharge pressure can rise to greater than 1,000 psi andcause unrealistic formation pressure estimates.

In this article, a new methodological approach has beenused to account for the effect of supercharging on formationpressure estimations. The method begins by modeling fluid flowwithin the filter cake and formation to estimate the amount ofsupercharged pressure in real time. The corrected pressure iscalculated by subtracting the estimate of supercharged pressurefrom the measured pressure. A new equivalent mud weight isthen calculated by using the corrected pressure. The formationpressures obtained by the FTWD tools are taken under varyingdownhole conditions to assess how forward modeling resultscorrelate with the analytical model results.

This new method was tested in one of Saudi Arabias fieldsin real-time while drilling a horizontal section. Repeat pressuretests were conducted a few days after the initial tests to verifythe accuracy of this mathematical model. This article discussesthe development of the supercharge pressure models, and theresults and observations from their testing.

INTRODUCTION

Wireline formation testers (WFTs) were introduced decadesago, prompting an industry debate regarding the significanceof the tools pressure measurements. The primary questionswere how they compared to well testing results and if theycould be reliable for formation evaluation. After years of test-ing and continuous improvement to WFT technology, pressuremeasurements from WFTs have proven to be the standard forformation evaluation. With the introduction of formation test-ing while drilling (FTWD) tools, debate has arisen once morewith respect to the significance of the pressure measurements

A New Real-Time Analysis Method for Pressure Tests in Low PermeabilityReservoirsAuthors: Mohammed F. Al-Zayer, Amer H. AbuHassoun, Dr. Sami Eyuboglu, Amir Anwar, Nacer Guergueb and Mark Proett



SINGLE-PHASE SUPERCHARGE MODEL

Assuming single-phase Darcy flow, the supercharge pressurecan be predicted using the familiar radial flow equations for aninfinite homogeneous reservoir:

(1)

It can be assumed that the mud cake is relatively thincompared to the wellbore diameter, i.e., lmc

This model assumes that the supercharged pressure isloosely coupled to the mud cake growth.

Assuming that the formation pressure is known, the follow-ing relationship can be developed to predict supercharging:

(12)

Single-phase Supercharge Simulation

A base example was demonstrated through research1 to illus-trate the supercharging effect with invasion time using the vari-ables shown in Table 1. This example has an overbalance of1,000 psi combined with a formation permeability of 1 md, re-sulting in significant dynamic supercharging effects, as demon-strated in Fig. 2. The supercharged pressure increases rapidly

during the very early time periods and then peaks as the mudcake grows and chokes off the invasion. This early invasionoccurs less than a minute after the formation is exposed to themud hydrostatic pressure. Then the supercharge pressureshows declination as the mud cake grows to its maximumthickness of 0.5 cm (0.2). At this point, the pressure begins toincrease at a slow rate and approaches the dashed line showingthe results for the static mud cake model. The static mud cakemodel assumes a mud cake of 0.5 cm was formed instantlywhen the wellbore was exposed to hydrostatic pressure. Thisresearch demonstrates that supercharged pressures predomi-nately decrease when the mud cake is growing and increase ata reduced rate when the mud cake has stabilized.

FIELD CASE STUDY

Supercharge analysis, as previously explained, was performedin real-time during the execution of tests of formation pressureusing a logging while drilling (LWD) 4 tool in a 6.125 bitsize horizontal hole. Water-based drilling fluid was used in thewell. A total of 17 valid tests were performed in this well, and1.5 md/cp of mobility was set as the threshold of a superchargeanalysis for this test.

The first test selected for supercharge analysis had an over-balance of 748 psi combined with mobility of 0.28 md/cp. Theconstants to perform the supercharge model for each selectedpoint are shown in Table 2.

The estimated supercharged pressure of 243.46 psi was cal-culated for Test 1 by using the supercharge model. The formationpressure determined from the LWD tool is shown with bluecolor in Fig. 3, while the corrected formation pressure, whichis the result of subtracting the supercharged pressure from the

Sensitivity Variable Units Base

Porosity (fraction) O 0.25

Viscosity (cp) 1

Flow Line Compressibility cfl (1/psi) 3 x 10-6

Mud Cake Permeability kmc (md) 0.0001

Mud Cake Max Thickness lmc (cm) 0.5

Wellbore Radius rw (cm) 10

Probe Radius rp (cm) 0.56

Packer Element Radius re (cm) 5

Formation Radius rf (cm) 10,000

Formation Height hz (cm) 10,000

Flow Line Volume Vfl (cc) 35

Pretest Chamber Volume Vpc (cc) 5

Table 1. Constants for simulations

Fig. 2. An example of supercharging effect using the variables from Table 1. Thedynamic mud cake growth model shows pressure increasing rapidly after exposureto hydrostatic pressure, and as the mud cake grows, the pressure decreases. Thestatic model shown with the dashed line illustrates how the supercharge pressurewould increase if the mud cake were formed instantly.



Viscosity (cp) *


Mud Cake Permeability kmc (md) *

Mud Cake Max Thickness lmc (cm) *

Wellbore Radius rw (cm) *



Formation Radius rf (cm) *

Formation Height hz (cm) *



Total Invasion Time (hours) 3.58

Table 2. Constants for simulations, Test 1*Parameters were modified to match formation and drilling fluid properties.



determined formation pressure, is shown with red color. The second test selected for supercharge analysis had an

overbalance of 911.5 psi combined with mobility of 1.21md/cp. Table 3 shows the constants to perform the superchargemodel for each selected point.

The estimated supercharge pressure of 91.28 psi was calcu-lated for Test 2 using the supercharge model. The formation

pressure determined from the LWD tool is shown with bluecolor in Fig. 4, while the corrected formation pressure, whichis the result of subtracting the supercharged pressure from thedetermined formation pressure, is shown with red color.

As mentioned earlier, one of the contributing factors to super-charge pressure is failure of the mud cake to fully form afterdrilling because of formation permeability, overbalance and in-vasion time. Therefore, two pressure tests were repeated whiletripping out of the hole at the same depths as Test 1 and Test 2to observe the changes in the pressure readings, helping todemonstrate the accuracy of the supercharged model, Table 4.The repeat test for Test 1 was performed with a determinedmobility of 0.37 md/cp; formation pressure was determined tobe R1 psi. The repeat test for Test 2 was performed with a determined mobility of 1.22 md/cp; formation pressure was determined to be R2 psi. The differences between the repeattest pressures and corrected formation pressures are 30.13 psiand 86.6 psi, respectively, for Tests 1 and 2.

CONCLUSIONS

Supercharging is a result of increased sandface pressure causedby an accumulation of mud filtrate in the wellbore region ofthe formation, particularly when the permeability of a forma-tion is low. The amount of supercharged pressure affecting thesandface pressure measured during drilling was estimated byusing finite difference forward modeling. Corrected pressuremeasurements were established by subtracting the calculatedsupercharged pressure measurements from the estimated

Fig. 3. The comparison of the LWD tool pressure and corrected formationpressure after subtracting supercharge pressure during Test 1.



Viscosity (cp) *


Mud Cake Permeability kmc (md) *

Mud Cake Max Thickness lmc (cm) *

Wellbore Radius rw (cm) *



Formation Radius rf (cm) *

Formation Height hz (cm) *



Total Invasion Time (hours) 4.7

Table 3. Constants for simulations, Test 2*Parameters were modified to match formation and drilling fluid properties.

Fig. 4. The comparison of the LWD tool pressure and corrected formationpressure after subtracting supercharge pressure during Test 2.

Test TVD (ft)Invasion

Time (hrs)Mobility (md/cp)

Pstop (psi)

Estimated Supercharge Pressure (psi)

Corrected Formation

Pressure (psi)

Differences between Repeat Test and

Corrected Formation Pressure (psi) (Z-R)

1 X,182.2 3.6 0.28 X1 243.6 Z1=X1-243.6 30.13

1R X,182.2 118 0.37 R1 R1

2 X,173.8 4.7 1.21 X2 91.28 Z2=X2-91.28 86.6

2R X,173.8 87 1.22 R2 R2

Table 4. Geotap pressure tests during drilling and repeat tests while tripping out of the hole



formation pressure readings. Repeat tests from the same loca-tions were performed at least 83 hours after the invasion timeof the first tests. Pressure readings showed similarity with cor-rected pressure readings after ignoring the supercharging ef-fects. The most important point of this research is that newequivalent mud weights were calculated using corrected pres-sures during drilling. The results proved successful for calculat-ing new mud weight and helping accomplish optimized drillingoperations.

ACKNOWLEDGMENTS

The authors would like to thank the management of SaudiAramco and Halliburton for their permission to publish thisarticle. The authors also acknowledge the contribution of theSaudi Aramco drilling team and Halliburton operations teamfor making the field studies possible with their efforts. Specialthanks are extended to Mohammed Bayrakdar, Halliburton,for his help with the field test and to Wael Soleiman, Hallibur-ton, for the supercharged forward modeling described in thisresearch.

This article was presented at the ADIPEC 2013 TechnicalConference, Abu Dhabi, UAE, November 10-13, 2013.

REFERENCES

1. Proett, M., Chin, W.C., Lysen, S., Sands, P. and Seifert, D.:Formation Testing in the Dynamic Drilling Environment,paper 2004-N, presented at the SPWLA 45th AnnualLogging Symposium, Noordwijk, The Netherlands, June 6-9, 2004.

2. Wu, J., Meister, M. and Li, B.: New Method forSupercharging Estimation, SPE paper 110389, presentedat the SPE Annual Technical Conference and Exhibition,Anaheim, California, November 11-14, 2007.

3. Wu, J., Torres-Verdn, C., Sepehrnoori, K. and Delshad,M.: Numerical Simulation of Mud Filtrate Invasion inDeviated Wells, SPE paper 71739, presented at the SPEAnnual Technical Conference and Exhibition, NewOrleans, Louisiana, September 30 - October 3, 2001.

4. Chenevert, M.E. and Dewan, J.T.: A Model for Filtrationof Water-based Mud during Drilling: Determination ofMud Cake Parameters, Petrophysics, Vol. 42, No. 3,May-June 2001.

5. Jiao, D. and Sharma, M.M.: Mechanism of Cake Buildupin Cross Flow Filtration of Colloidal Suspension, Journalof Colloid and Interface Science, Vol. 162, No. 2, February1994, pp. 454-462.

6. Chin, W.C.: Quantitative Methods in ReservoirEngineering, Amsterdam and Boston: Gulf ProfessionalPublishing, USA, with Elsevier Science, July 2002, 480 p.

BIOGRAPHIES

Mohammed F. Al-Zayer is aPetrophysicist in the ReservoirDescription Division of Saudi Aramco.Since joining Saudi Aramco in 2010,he has been involved in severaltechnical petrophysical disciplines ofthe Ghawar field. Mohammed is

logging while drilling formation testers as well as advancedtools.

In 2010, he received his B.S. degree (with honors) inPetroleum and Natural Gas Engineering from West VirginiaUniversity, Morgantown, WV. Currently, Mohammed ispursuing his M.S. degree in Petroleum Engineering atImperial College London, London, U.K.

Amer H. AbuHassoun joined SaudiAramco in 2001 as a CertifiedPetroleum Engineer and has since thengained hands-on experience focusing onreservoir management, reservoir charac-terization, drilling and productionengineering in both sandstone and

of the Southern Reservoir Management Department as aSenior Reservoir Management Engineer. Amers focus is onmanaging the reservoir performance of the worlds largestintelligent field: the Khurais complex. He has authoredseveral technical publications focusing on restoringproduction utilizing an asset team approach, intelligent fieldtechnology and enhancement of injection trends.

In 2001, Amer received his B.S. degree from King FahdUniversity of Petroleum and Minerals (KFUPM), Dhahran,Saudi Arabia, and in 2007, he received his M.S. degreefrom Texas A&M University, College Station, TX, both inPetroleum Engineering.

Dr. Sami Eyuboglu became a ProgramManager at the Halliburton DhahranTechnology Center, Saudi Arabia, inFebruary 2012. He has been withHalliburton Energy Services since April2008. Sami specializes in both loggingwhile drilling and wireline pump-out

at Ohio State University, where he worked in developingcomputer programs for surface geophysical methods andnumerical modeling of ground penetrating radar (GPR).Their applications included national security issues (UXOand tunnel detection) and the environment.

Sami received his B.S. and M.S. degrees in MiningEngineering from Hacettepe University, Ankara, Turkey,and his Ph.D. degree in Applied Physics from the Universityof Arkansas at Little Rock, Little Rock, AR.



mostly interested in advanced applications of wireline and

carbonate reservoirs. He currently works in the Khurais Unit

formation testers. Prior to this, he was a Research Professor

Amir Anwar is a Senior Logging WhileDrilling (LWD) Technical Professionalfor Sperry Drilling-Halliburton,located in Saudi Arabia. He has morethan 8 years of LWD experience. Amirstarted as a LWD Field Engineer, thenafter 4 years, he then joined the Real-

ROC professional. In his current role, Amir works ondelivering analysis and LWD solutions to Saudi Aramcoutilizing existing and emerging LWD technologies.

He received his B.S. degree in Mechatronics Engineeringfrom the Sixth October University, Cairo, Egypt. Amir ismember of the Society of Petrophysicists and Well LogAnalysts (SPWLA) and the Society of Petroluem Engineers(SPE).

Nacer Guergueb is the Formation andReservoir Solutions Senior Managerfor wireline and perforating in SaudiArabia. He has more than 18 years ofexperience in wireline logging,including open and cased holeoperations. For the last 12 years,

Services Group, located in several different areas, includingWest Africa, the Far East and the Middle East, where heassisted in logging operations, developing log qualityprocesses, working on special projects and supportingcustomers Geosciences asset teams.

In 1995, Nacer received his State Engineer degree inGeophysics from the University of Sciences and Technology,Algiers, Algeria. He is a member of Society of ExplorationGeophysicists (SEG), the Society of Petrophysicists andWell Log Analysts (SPWLA) and the Society of PetroleumEngineers (SPE).

Mark Proett is a Senior PetroleumEngineering Consultant for theUpstream Group of the AramcoServices Company, Houston, TX. Hewas previously with Halliburtonserving as the Global TechnicalAdvisor for Formation Testing and

advocating the viability of the formation testing whiledrilling (FTWD) tool, introduced in 2002 with the SperryGeoTap service. He is also known for developing newmethods of pressure transient analysis and sampling probeinnovations, such as the oval probe and focused samplingprobes.

Mark has been awarded 50 U.S. patents and hasauthored over 50 technical papers, most of which deal withsampling and testing analysis methods. He has served ontechnical committees for the Society of Petrophysicists andWell Log Analysts (SPWLA) and Society of PetroleumEngineers (SPE), and also as the Chairman for the SPEPressure Transient Testing Committee. Mark was a SPWLADistinguished Speaker in 2004/2005 and a SPE Distin-guished Lecturer for 2006/2007. In 2008, he received theSPWLA Distinguished Technical Achievement Award andin 2013 the SPE Gulf Regional Formation EvaluationAward.

Mark received his B.S. degree in MechanicalEngineering from the University of Maryland, College Park,MD, and his M.S. degree from Johns Hopkins University,Baltimore, MD.



time Operations Center (ROC) for 1 year as a Senior LWD Sampling. Mark is best known for his publications

Nacer was the Lead in the Applied Formation Evaluation

ABSTRACT waterflooded field on production to establish fluid pathwaysbetween selected injectors and producers, and obtain informa-tion about the fluid flow mechanism in the reservoir. The resultof this project will improve understanding of reservoir fluidflow and positively affect the reservoir management strategy toimprove sweep and enhance oil recovery in this field.

Objective

This IWTT project focused on delivering several key elements:estimation of water breakthrough time between injectors andproducers, determination of fluid pathways between wells, assessment of the traveling velocity of injected water and anoverall picture of water breakthrough in Field-X.

Concept

A tracer is an identifiable substance added to injected fluid.When the tracer is detected and sampled at the producers, itcan provide valuable information on the path the fluid follows.The IWTT technology is an extremely valuable tool for pro-duction optimization and understanding reservoir dynamics.This technology is often used in the oil industry to estimateresidual oil saturation, assess volumetric sweep efficiency andprovide information on the location and orientation of frac-tures within naturally fractured reservoirs.

Procedure

The IWTT technology is based on information obtainedthrough well-to-well communication and tracer sampling col-lection. Tracers are injected in each injector well to monitorthe source of water breakthrough and verify communicationswith all offset wells. Certain tracer types are selected for injec-tion at specific injectors, and samples are then collected fromseveral offset wells and shipped to the Institute for EnergyTechnology laboratories in Norway, where several analyses aremade. Each injector carries a distinctive type of chemical tracerto easily trace back the water source after sampling in the pro-duction streamline detects a tracer presence. The collective re-sults from all chemical tracers highlight all possible commu-nication pathways between injectors and offset wells.

High-quality reservoir characterization, improved reservoir dy-namics, optimized water flooding and a better understandingof fluid movements are some key factors for successful reser-voir management. Interwell tracer test (IWTT) technology hasbeen recognized as an efficient tool to determine fluid path-ways between wells and evaluate areal water breakthrough between injectors and producers, along with estimating the ve-locities at which the injected water is breaking through. Thesedata can be integrated in the geological and reservoir modelsof the field to reduce uncertainties attributed to fluid flowmechanisms and interwell communication.

This article presents a case study of IWTT technology appli-cation in a heterogeneous reservoir in a Saudi Arabian oil field.It shows how this characterization tool was utilized to investi-gate the reservoir flow mechanism and how the derived infor-mation facilitated better reservoir management through im-proved reservoir monitoring and enhanced understanding ofreservoir fluid dynamics. The project began in November 2007by injecting unique chemical tracers into a set of injectors toeffectively monitor injected fluid movement in the reservoir, after which the tracers were continuously monitored throughyearly sampling programs by collecting samples from adjacentoil producers.

The results of the project have provided valuable insights byidentifying interwell pathways, estimating velocities at whicheach tracer the injected water is traveling and optimizingwater injection volumes. These findings translated into opti-mized reservoir management, resulting in a tangible impact onthe offset wells productivity and sustainability.

INTRODUCTION

History

Field-X is considered one of the most challenging areas inSaudi Arabia. This is due to the fields complexity, includingthe existence of intense fractures and super permeable streaksthat have resulted in anomalous water encroachment patternsin the field. Therefore, an interwell tracer test (IWTT) projectwas proposed and commenced 52 months after putting this


Improved Reservoir Surveillance throughInjected Tracers in a Saudi Arabian OilField: Case Study

Authors: Muhanad A. Al-Mosa, Husain A. Zaberi and Dr. Olaf Huseby


METHODOLOGY

Operational Highlights

This IWTT project was carried out over a five-year period,which provided adequate time to qualitatively and quantita-tively capture the tracers different responses, and to distinguishfluid movement for further reservoir heterogeneity and connec-tivity analysis. The project design was for a distinctive fluidwith a known concentration basically composed of a chemi-cal tracer and water to be injected into the reservoir at aninjector for a certain period of time and then produced backfrom the offset wells. At the injector, water accompanied bythe specified chemical tracer gets injected into the reservoir.The assumption is that fluid carrying the tracer is mixed withformation water and oil, and then gets pushed further into the reservoir. Depending on the area, this fluid may travelthrough the reservoirs rock matrix, which in turn provides the needed pressure support and enhances sweep efficiency inthe area. On the other hand, this fluid may travel through highpermeability channels (fractures and super permeable layers)that are connected through long pathways, which means injected water is being directly produced without delivering the desired efficient areal pressure support. A sampling pro-gram, initially developed with certain criteria regarding the location and performance of the offset wells, is then flowed tocapture and analyze samples at the production streamline forfurther investigation, comparing them with the original fluidconcentration.

Reservoir heterogeneities, such as super permeability, frac-ture intensity and the relatively flat structure of Field-X, playmajor roles in the anomalous water arrival to these offset wellscompared to other areas. This IWTT project led to a better un-derstanding of fluid dynamics, which paved the way to betterreservoir management optimization practices in this particularanisotropic area with irregular water encroachment and pres-sure propagation. Taking into account that the distances between the injectors and the producers are considerable,breakthrough is greatly dependent on reservoir rock quality.This part of the field is known to be heterogeneous, and break-through was, initially, anticipated to occur in the very early lifestage after the start-up of tracer injection.

Frequency

The IWTT project began in November 2007. Five different


Tracer Name Injected Amount (kg)

Injection Well Well Type

Injection Date (D-M-Y)

Time Before First Observation in a Producer Well (Months)

2-FBA 79 I-3 Horizontal Nov. 5, 2007 18 (in P-1 and P-2)

4-FBA 79 I-4 Horizontal Nov. 6, 2007 Not observed yet

2,6-DFBA 36 I-5 Vertical Nov. 7, 2007 Not observed yet

3-TFMBA 13 I-1 Vertical Nov. 3, 2007 Not observed yet

4-TFMBA 34 I-2 Vertical Nov. 4, 2007 18 (in P-1)

Table 1. Tracer injections in Field-X

Fig. 1. IWTT sampling programs since the startup of tracer injection.

Fig. 2. Tracer breakthrough at five offset wells since the startup of tracer injection.

Fig. 3. Bands of sampling frequency for IWTT 2012-2013 sampling programs.


types of chemical fluorobenzoic acid (FBA) tracers were selected,and each was injected into one of five injectors located along thewest flank of Field-X, Table 1 and Figs. 1 and 2. Until March2008, samples were collected from 10 offset wells on a biweeklybasis. The assumption was that tracers would most likely reachthe offset wells very soon, however, no sign of any of the injectedtracers was noticed in any of the offset wells during the first sixmonths. Therefore, the sampling frequency was changed to amonthly basis and broken down into a number of bands, Fig. 3.

RESULTS AND DISCUSSION

Timeline

These five chemical tracers were injected into five injectors inthe field, one unique tracer per individual well, during a periodof five days in November 2007. Two of these tracers (2-FBAand 4-TFMBA) have so far been observed at producers in thefield. Figures 4 to 6 show a comprehensive breakdown of theIWTT projects timeline progress since initiation, displaying allthe main event occurrences where certain chemical tracerswere captured at several offset wells.

Major Observations

1. Chemical tracers were first detected in water samples collected at two offset wells (P-1 and P-2) after 18 months of tracer injection, which began in November 2007. These tracers were linked to only two injectors: I-2 and I-3.

2. 26 months after tracer injection start-up, tracers were seen at offset wells P-1 and P-3. The tracers were linked to one injector: I-3.

3. 44 months after tracer injection start-up, tracers were seen atoffset well P-5. The tracers were linked to one injector: I-2.

4. 46 months after tracer injection start-up, tracers were seen atoffset well P-5. The tracers were linked to one injector: I-3.

5. 47 months after tracer injection start-up, tracers were seen atoffset well P-4. The tracers were linked to one injector: I-3.The fact that three out of five tracers have not been ob-

served so far should not be misinterpreted as evidence of thedegradation, adsorption or other problems with the tracers.The FBA tracers used in the field are among the best testedchemical tracers and have all been proven to survive in carbonateas well as sandstone reservoirs for more than six years at reser-voir temperatures of 135 C. Moreover, the FBA tracers have

Fig. 4. Detection timeline since startup of tracer injection.

Fig. 5. IWTT detection timeline for I-2 and I-3.



all been proven to behave as ideal water tracers, without ad-sorption to the rock in either carbonate or sandstone reser-voirs. The fact that two of the five tracers have been observedin the field provides an additional confirmation of the stabilityof the tracers. The chemical properties of the five tracers in-jected into the field are equal, so if two of them have survivedthrough the field, the remaining three should also survive.

Two explanations are possible for the lack of tracer produc-tion from the I-1, I-4 and I-5 injectors. One possibility, whichhas also been observed in other fields, is that the injected waterand the tracers go mainly into an aquifer, where the tracers arediluted to levels below the detection limit of 50 parts per tril-lion (ppt). In any tracer study design, one must consider thepossibility of dilution in water either in the reservoir or in ad-jacent aquifers. If a large fraction goes into the aquifer, morethan expected for a given tracer injection well, the dilutionmay be too large, preventing tracer detection at the producers.The small concentration values observed in the producers thatdo produce tracers in the field (with a maximum of 10 timesthe detection limit) suggest that the tracers are being dilutedmore than was originally assumed in the design phase of theproject.

Another possibility is that the injected water provides pres-sure support to the aquifer without inducing large enough fluxwithin the time span of the sample collection and analysis. Thefact that the residence times are fairly long in the wells produc-ing tracers supports the latter explanation.

Integrating a Tracers Production Curve Analysis with

Analytical Tools

Tracer concentration response curves offer distinctive insightsinto the reservoir characteristics, providing a means for rigorousevaluation of reservoir heterogeneity. The results from such ananalysis were used to quantify all possible communications be-

tween the injectors and producers, to demonstrate flow pat-terns and to evaluate the sweep efficiency in this part of thefield. The curves provide significant information, such as re-covered tracer mass, first tracer breakthrough and peak tracerconcentration. For instance, tracer concentration responsecurves are indicative of a homogeneous reservoir if a tracer isdetected sometime after tracer injection and its detection con-centration increases gradually with time. Conversely, if thetracer concentration approaches a peak value and then de-creases sharply to zero over a short period of time after the injection start-up, it is an indication of fracture corridors or super permeability streaks between the water injector and theoil producer1.

As the flood front reaches an area characterized by fracturenetworks, the tracer travels at a much higher velocity due tothe high-pressure differential across the fractured high per-meability zone compared to that in the zone dominated with matrix permeability. This, in turn, causes the tracer travelingwith the flood front to reach producers faster, which results ina high tracer concentration at the offset wells. As a result, thefirst tracer concentration peak can confirm the presence of ahigh permeability feature connecting the injector and the producer. An overview and analysis of the tracer responsecurve for each well where tracers were detected are discussedin detail.

Residence Time Distribution from Tracer Production Curves

Residence time distribution (RTD) analysis is a powerful toolthat can be used to assess several characteristic properties offlow in a system. It was originally developed to describe flowin chemical reactor systems2 and since then has been used tointerpret tracer data: several authors have extended RTDmethodology to estimate flow geometry and heterogeneity in areservoir from the data in tracer curves3, 4. Shook et al. (2009)5

shows how RTD methodology can be used to estimate oil satu-ration from partitioning interwell tracer test (PITT) data; themethodology was used6 to analyze data from a pilot test ofnew PITT tracers in the Lagrave field. The method was alsoused to analyze tracer data to optimize a surfactant field trialin the Minas field7.

RTD is the distribution of times used by a population oftracer particles to travel through a medium. The tracers repre-sent fluids that travel along different paths, and therefore, usedifferent amounts of time to pass through a medium. The dis-tribution, E(t), of these times is called the exit age distribution,or RTD of the fluid in the system. E(t) is defined from pro-duced tracer concentrations, C(t), production rate, Qp(t), andinjected tracer amount, M, as

(1)

The unit of E is the inverse of the time unit. If a system hasone injector and multiple producers, j, with different production

Fig. 6. IWTT detection timeline graph.



rates, Qj, we can define the RTDs between each injector and jas

(2)

In a closed system, the normalization by injected traceramount ensures that

(3)

where the sum is over all producers. If reservoir boundaries areopen, significant amounts of tracer may be lost. The producedtracer can nevertheless be analyzed, and the RTD will give in-formation about the injector-producer pairs, though clearly alost tracer does not give information3.

Important information about the geometry and flow in asystem can be obtained from the RTDs two first moments.They are given as

(4)

where the zero moment represents the relative amount oftracer produced in production well j, and the first moment rep-resents the average residence time for the tracers between theinjection well and j.

In 2005, a new method3, 4 was introduced to characterizethe flow and geometry of a system using RTD. In this method,two functions, the flow capacity, F(t), and the storage capacity,(t), can be defined as

(5)

and combined in a F diagram to quantify a measure of theheterogeneity of the system. The swept reservoir volume as afunction of time can be estimated from F(t)5 as

(6)

Correcting Tracer Data for Reinjection

In cases where produced fluid is reinjected, any contribution inthe tracer curves due to reinjection must be removed prior toRTD analysis. For completeness, we have summarized themain steps in this correction6.

The correction can be done in a systematic and unambigu-ous manner using deconvolution. The RTD at the outlet can bewritten as the convolution of the input signal and the injector-producer well pairs RTD function8:

(7)

If we reinject tracer, with a normalized reinjection concentrationdenoted by Er(t), the function that describes the total injectedtracer is given by Ein= (t)+Er(t) for t >0, where the Dirac dis-

tribution represents the initial tracer pulse injection. Settingthis into Eqn. 7 and using the definition of the Dirac distribu-tion and the commutative property of convolution integrals,we find

(8)

This result states that at a given time, t, the true tracerdistribution from the delta pulse injection without reinjectionis given by the observed distribution Eout(t), minus the integralup to t of the true distribution and the known reinjectiontracer distribution.

Extrapolation of Tracer Results to Infinite Times

Moment analysis of tracer curves requires that RTDs be inte-grated to infinity. This is not possible using measured dataalone, as any tracer campaign must be ended at some finitetime after injection. To compensate for this, integration to in-finity must therefore be based on extrapolation of the tracercurves. It has been shown4 that extrapolation of RTDs can bedone by fitting an exponential function to the tracer data forlarge times. If large time data are unavailable, it may be diffi-cult to use a log-linear fit. A different approach, based on fitting a type curve function to the complete data set, wastherefore used6. Based on a solution to the convection-diffu-sion equation in known geometries9, 10, the type function withthree parameters, D0, t0 and M0, was defined and used to fitdata as:

(9)

Examples of these extrapolations are displayed in Figs. 7 and8 showing the RTD analyses for tracers and wells where non-zero concentrations were observed. In the figures, the open cir-cular symbols and light blue shaded area are E(t) from themeasured data. The curve used to extrapolate E(t), based onEqn. 9, is displayed as a black line. The actual extrapolated re-gion is given as a red shaded area below the extrapolation curve.

It should be noted that for some of the tracers and wells, theextrapolations are fragile as the tracers have not yet reachedtheir peaks. This is the case for the 2-FBA curves in P-3, P-4and P-5, and for the 4-TFMBA curve in P-5. For these curves,the RTD analysis should be treated with caution. For the 2-FBA curves in P-1 and P-2, and for the 4-TFMBA curve in P-1,the tracers seem to have reached their peak, and the RTDanalysis for these wells should be robust enough that soundconclusions can be established.

Recovery of a Tracer

Recovery of a tracer in a well is given by the zero moment, aspreviously illustrated by Eqn. 4, of the RTD. Due to the nor-malization, recovery of a tracer, summed over all producers,



should sum to 100% for a closed system. For a given well, j, therecovery quantifies how much of the injected tracer is producedin that particular well. Table 2 summarizes the recovery of the2-FBA and 4-TFMBA tracers.

From Table 2, we note that the recovered tracer is verysmall on the order of 0.1% of the injected tracer mass. Thisis very small compared to recoveries reported in other cases6, 7,11. On the other hand, the tracer curves in Fig. 9 are distinct and

Fig. 7. RTD analysis of the 2-FBA tracers, injected at I-3 and detected in P-1, P-2, P-3, P-4 and P-5. The open circular symbols are 2-FBA data, and the dashed line is thecorresponding type curve fit defined in Eqn. 9. The light blue area corresponds to the integral of the RTD for the measured data, and the red area corresponds to theintegral of the RTD for the extrapolation. The full RTD is assumed to be the combined blue and red areas



clear, and represent a breakthrough of water from the individualinjection wells albeit a small breakthrough. The small amountrecovered suggests that the water injection is effective and isworking as desired. The water is injected into the aquifer, below

the oil-water contact, and helps to maintain pressure ideallywithout inducing significant water breakthrough at the producers.We also note that these low concentrations could not have beenquantified without excellent detection limits. The measured

P-1 P-2 P-3 P-4 P-5 Sum

Tracer mO [%] mO [%] mO [%] mO [%] mO [%] mO [%]

2-FBA 0.10 0.05 0.04 0.16 0.04 0.39

4-TFMBA 0.21 - - - 0.02 0.23

Table 2. Recovery of tracers 2-FBA and 4-TFMBA, obtained from the zero moment of the RTD

Fig. 8. RTD analysis of the 4-TFMBA tracers, injected at I-2 and detected in P-1 and P-5. The open circular symbols are 4-TFMBA data, and the dashed line is thecorresponding type curve fit defined in Eqn. 9. The light blue area corresponds to the integral of the RTD for the measured data, and the red area corresponds to theintegral of the RTD for the extrapolation. The full RTD is assumed to be the combined blue and red areas.

Fig. 9. Tracer concentrations in wells P-1, P-2, P-3, P-4 and P-5; (a) displays responses of the 2-FBA tracer injected at I-3, and (b) displays responses of the 4-TFMBAtracer injected at I-2.



cates the degree of heterogeneity of the reservoir. For a frac-tured rock, e.g., if large parts of the flow occur in a small frac-tion of the space, F would increase fast with increasing f .

The heterogeneity can be quantified by the Lorentz coeffi-cient, defined by the area between the Ff curve and the diag-onal, normalized by half5:

(10)

Lc is zero for a completely homogeneous flow and 1 for acompletely heterogeneous flow (all flow in infinitely narrowchannels). Shook et al. (2009)5 reports Lc = 0.18 for a homoge-neous 5-spot and Lc = 0.7 for the fractured Beowawe geothermalreservoir. For the well pairs considered in this case study, the 2-FBA tracer yields Lc = 0.12 in P-1, the 4-TFMBA tracer yieldsLc = 0.16 in P-1, and the 2-FBA tracer yields Lc = 0.16 in P-2.

This indicates that the swept volume between I-3 (the 2-FBAinjector) and P-2 is similar, with respect to heterogeneity, to theswept volume between I-2 (the 4-TFMBA injector) and P-1,and that the swept volume between I-3 and P-1 is slightly lessheterogeneous. Note that similar plots and analysis can, in

concentrations represent the detection and quantification ofconcentrations down to 50 ppt (1x10-12 kg/l). This is 1,000times lower than values reported in other applications7.

As discussed in other work3, the RTD methodology workswell even for systems with open boundaries, such as this field.Obviously, when reservoir boundaries are open and tracer re-mains in the reservoir, the unproduced portion of tracer cannotprovide information. The tracer that is recovered does containinformation on the pore space sampled by that tracer as ittraveled from injector to producer. Based on the clear tracercurves in Fig. 9, we therefore decided to use the data for RTDanalysis to extract as much information as possible from thetracers, despite the small recovery factors.

Average Residence Time

The residence times for the tracers are given by the normalizedfirst moment of the RTD, T = m1,j /m0,j. As these factors de-pend on an extrapolation to infinity, the caution for the 2-FBAcurves in P-3, P-4 and P-5, and for the 4-TFMBA curve in P-5is considered, whereas the average residence times for the 2-FBA curves in P-1 and P-2, and for the 4-TFMBA curve in P-1are more robust.

Clearly, the average residence times, provided in Table 3, arerelatively long. The shortest one (1,296 days) corresponds to3 years, and the longest one (2,185 days) corresponds to al-most 6 years. The long residence times suggest that the injectedwater moves fairly slowly through the reservoir from injectorto producer. This is indeed consistent with injection into theaquifer and supports the observation of low recovery of tracer.It indicates that the water injection is effective and is workingas planned.

Quantification of Heterogeneity of the Flooded Region

The flow capacity, F(t), and the storage capacity, f (t), were es-timated from the 2-FBA tracer data in P-1 and P-2 and the 4-TFMBA tracer data in P-1, using Eqn. 5. These functions aresummarized in the Ff plots in Fig. 10. Generally, the Ffcurves can be used to quantify the flow between an

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