Autumn 2013

Acidizing Advances

Monitoring Casing Corrosion

Geomagnetic Referencing

Solar Storms

Oilfield Review

13-OR-0004

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Widely hailed as a breakthrough technology, extended-reach drilling enables cost-effective development of off-shore reserves from shore-based locations and centrally located platforms. In addition, it achieves maximum con-tact with the reservoir and accesses multiple reservoirs with a single wellbore.

For Eni US Operating Company Inc., extended-reach drilling has been instrumental in our development of the Nikaitchuq eld off the North Slope of Alaska, USA. The elds characteristicsfrom its offshore location and downhole temperature to its complex geologymake this a highly challenging project.

Our leases are offshore in the Arctic Ocean and the Beaufort Sea north of the Arctic Circle. For better access to the reservoir, weve built an island a few miles offshore, in less than 10 ft [3 m] of water. Of the 30 wells we plan to drill from the single pad on the man-made island, we have drilled 17; we have also drilled 22 from an onshore pad located at Oliktok Point. In addition to the economic bene-ts, restricting drilling sites to just two pads minimizes our environmental footprint.

The reservoir we are targeting is shallow and relatively cool, making the oil viscous. This reservoir had been devel-oped as a line-drive waterood for optimal oil recovery; the development plan features alternating horizontal injectors and producers, with a total of 52 wells to be completed by 2014. The injection water for waterood is produced from a deeper, warmer formation.

We are drilling shallow, extended-reach wells. While these wells are between 3,200 ft [1,000 m] and 4,200 ft [1,300 m] deep, some are more than 23,000 ft [7,000 m] long. More than 90% of the wells in the development have a reach/TVD ratio of more than 4 and some are as high as 6. The wells are spaced 1,200 ft [370 m] apart along their production intervals, and several follow faults that compartmentalize the reservoir. Accurate well placement is crucial to ensure we dont short-circuit the waterood or inadvertently cross a major fault. A 1% location error in a 23,000-ft long well translates into an unacceptable error of more than 200 ft [60 m] at TD.

This is where geomagnetic referencing comes in. Although traditional gyroscopic surveys could produce data of sufcient quality to achieve the necessary well-bore placement positions, gyro surveys are impractical in this environment and require additional costs and time that make them prohibitively expensive for drilling pro-grams in this area. Geomagnetic referencing provides us with real-time, precise positioning and the certainty of knowing where our wellbores are without having to stop

Geomagnetic Referencing for Well Placement

1

the drilling process. By using geomagnetic referencing, we are able to construct a detailed model of the Earths magnetic eld for comparison with magnetic measure-ments acquired while drilling (see Geomagnetic ReferencingThe Real-Time Compass for Directional Drillers, page 32). The model is made up of contribu-tions from the Earths main magnetic eld, the local mag-netic variations in crustal rocks and time-varying disturbances caused by solar activity.

Solar-related magnetic storms occur unpredictably, and at Arctic latitudes, they generate high-amplitude swings in magnetic eld strength and direction that must be incor-porated into the model. To quantify these disturbances, Schlumberger partnered with the US Geological Survey to build a geomagnetic observatory nearby in Deadhorse, Alaska. The observatory supplies the high-quality referenc-ing data required for real-time drill-ahead corrections and for denitive surveys at the end of each bottomhole assem-bly run.

We are drilling our 39th well using geomagnetic refer-encing. Since the earliest applications of this technology in our wells, our wellbore position uncertainty has continually decreased. And because we know the positions with a high degree of certainty, we are reentering wells to create dual laterals from single laterals. This strategy allows us to essentially double the wellbore contact with the reservoir and increase production rates. Even with these increased rates, we expect to produce from this eld for more than 30 years.

Andrew BuchananSenior Operations GeologistEni US Operating Company Inc.Anchorage, Alaska, USA

Andrew Buchanan is the Senior Operations Geologist with Eni US Operating Company Inc. in Anchorage, where he has been since 2009. He previously worked for ASRC Energy Services as a geologic consultant. Andrew earned a BS degree in geology from the University of Regina, Saskatchewan, Canada. He currently serves as Past President of the Petroleum Club of Anchorage.

www.slb.com/oilfieldreview

Schlumberger

Oilfield Review

1 Geomagnetic Referencing for Well Placement

Editorial contributed by Andrew Buchanan, Senior Operations Geologist, Eni US Operating Company Inc.

4 Stimulating Naturally Fractured Carbonate Reservoirs

Stimulation of naturally fractured carbonate reservoirs has improved signicantly with the application of innovative acidizing uids that contain degradable bers. The bers congregate and form barriers that impede uid movement into fractures, redirecting the acid to lower permeability regions. This type of enhanced stimulation efciency has led to increasingly uniform production proles across multiple zones and substantial production increases in many oil and gas elds worldwide.

18 Casing Corrosion Measurement to Extend Asset Life

Corrosion in downhole tubulars may shorten a wells produc-tive life and contribute to costly damages for operators. Downhole corrosion monitoring serves as the rst line of defense against casing corrosion.

Executive EditorLisa Stewart

Senior EditorsTony SmithsonMatt VarhaugRick von Flatern

EditorRichard Nolen-Hoeksema

Contributing EditorsH. David LeslieTed MoonParijat MukerjiErik NelsonGinger OppenheimerRana Rottenberg

Design/ProductionHerring DesignMike Messinger

IllustrationChris LockwoodMike MessingerGeorge Stewart

PrintingRR DonnelleyWetmore PlantCurtis Weeks

Oilfield Review is published quarterly and printed in the USA.

Visit www.slb.com/oilfieldreview for electronic copies of articles in English, Spanish, Chinese and Russian.

A free iPad app is available for download.

2013 Schlumberger. All rights reserved. Reproductions without permission are strictly prohibited.

For a comprehensive dictionary of oilfield terms, see the Schlumberger Oilfield Glossary at www.glossary.oilfield.slb.com.

About Oilfield ReviewOilfield Review, a Schlumberger journal, communicates technical advances in finding and producing hydrocarbons to customers, employees and other oilfield professionals. Contributors to articles include industry professionals and experts from around the world; those listed with only geographic location are employees of Schlumberger or its affiliates.

On the cover:

The aurora borealis appears as shim-mering curtains of colored light in the Arctic regions of the Earths northern hemisphere. Auroras, which may occur in both of the Earths polar regions, are created when emissions from solar ares and coronal mass ejections inter-act with the Earths magnetic eld. A large loop of plasma, referred to as a prominence, emanates from the Suns surface (inset). Such a mass of plasma ejected in the direction of the Earth would create space weather events that could disrupt modern electromag-netic-related technologies, including well guidance methods that depend on magnetic measurements.

2

Autumn 2013Volume 25Number 3

ISSN 0923-1730

61 Contributors

63 Defining Production Logging:Principles of Production Logging

This is the eleventh in a series of introductory articlesdescribing basic concepts of the E&P industry.

3

32 Geomagnetic ReferencingThe Real-TimeCompass for Directional Drillers

In recent years, demand for accurate wellbore placementhas driven technology developments that have advanced thescience of wellbore guidance. This article examines magneticsurveying methods that improve real-time measurementaccuracy and allow drillers to reach their targets efcientlyand cost-effectively.

48 Blowing in the Solar Wind: Sun Spots,Solar Cycles and Life on Earth

Space weather can affect terrestrial systems that are crucialfor modern society. This article describes solar events thatcontribute to space weather and are the source of electro-magnetic pulses that have the potential to disrupt anddamage electronic, power, communication, transportationand other infrastructure technologies on Earth and in space.Solar sunspot cycles and their inuence on solar and terres-trial weather are also discussed.

Hani ElshahawiShell Exploration and ProductionHouston, Texas, USA

Gretchen M. GillisAramco Services CompanyHouston, Texas

Roland HampWoodside Energy Ltd.Perth, Australia

Dilip M. KaleONGC Energy CentreDelhi, India

George KingApache CorporationHouston, Texas

Andrew LodgePremier Oil plcLondon, England

Advisory Panel

Editorial correspondenceOilfield Review5599 San FelipeHouston, TX 77056United States(1) 713-513-1194Fax: (1) 713-513-2057E-mail: editorOilfieldReview@slb.com

SubscriptionsCustomer subscriptions can be obtainedthrough any Schlumberger sales office.Paid subscriptions are available fromOilfield Review ServicesPear Tree Cottage, Kelsall RoadAshton Hayes, Chester CH3 8BHUnited KingdomE-mail: subscriptions@oilfieldreview.com

Distribution inquiriesMatt VarhaugOilfield Review5599 San FelipeHouston, TX 77056United States(1) 713-513-2634E-mail: DistributionOR@slb.com

4 Oileld Review

Stimulating Naturally Fractured Carbonate Reservoirs

Naturally fractured carbonate reservoirs can be difcult to stimulate because

treatment uids tend to enter the fractures and avoid less permeable regions.

Effective uid diversion techniques are usually necessary to ensure that stimulation

uids contact the largest possible reservoir surface area. Engineers and chemists

have developed an innovative acidizing uid that employs degradable bers to

temporarily block permeable fractures and force the uid into less permeable zones.

Operators have applied the ber-laden acid to naturally fractured oil and gas reser-

voirs in which achieving complete zonal coverage is difcult and, as a result, have

witnessed substantial production improvements.

Khalid S. AsiriMohammed A. AtwiSaudi AramcoUdhailiyah, Saudi Arabia

Oscar Jimnez BuenoPetrleos Mexicanos (PEMEX)Villahermosa, Mexico

Bruno LecerfAlejandro PeaSugar Land, Texas, USA

Tim LeskoConway, Arkansas, USA

Fred MuellerCollege Station, Texas

Alexandre Z. I. PereiraPetrobrasRio de Janeiro, Brazil

Fernanda Tellez CisnerosVillahermosa, Mexico

Oileld Review Autumn 2013: 25, no. 3. Copyright 2013 Schlumberger.For help in preparation of this article, thanks toCharles-Edouard Cohen, Rio de Janeiro;Victor Ariel Exler, Maca, Brazil; Luis Daniel Gigena, Mexico City; Daniel Kalinin, Al-Khobar, Saudi Arabia; and Svetlana Pavlova, Novosibirsk, Russia.ACTive, MaxCO3 Acid, POD, SXE and VDA are marks of Schlumberger.

1. Crowe C, Masmonteil J, Touboul E and Thomas R: Trends in Matrix Acidizing, Oileld Review 4, no. 4 (October 1992): 2440.

2. Robert JA and Rossen WR: Fluid Placement and Pumping Strategy, in Economides MJ and Nolte KG (eds): Reservoir Stimulation, 3rd ed. Chichester, West Sussex, England: John Wiley & Sons, Ltd (2000): 19-219-3.

Autumn 2013 55

Since the dawn of the oil and gas industry, opera-tors have endeavored to maximize well productiv-ity, employing a variety of techniques to do so. For example, as early as the 19th century, engineers began pumping acid in wells to improve produc-tion. Acidizing treatments dissolve and remove formation damage resulting from drilling and completion operations, create new production pathways in producing formations or both.

Acidizing treatments fall into two categories. Matrix acidizing consists of pumping uid into the formation at rates and pressures that will not fracture the reservoir. The resulting treatment stimulates a region extending up to about 1 m[3 ft] around the wellbore. Fracture acidizing is a hydraulic fracturing treatment that pumps acid during at least one uid stage. The stimulation distance may extend one or two orders of magni-tude farther into the formation than that achieved by matrix acidizing.

The composition of acidizing uids depends on the type of formation to be stimulated. Carbonate formations, composed mainly of lime-stone (calcium carbonate [CaCO3]) or dolomite (calcium magnesium carbonate [CaMg(CO3)2]),are treated with hydrochloric acid [HCl], various organic acids or combinations thereof. Sandstone formations typically consist of quartz [SiO2] or feldspar [KAlSi3O8NaAlSi3O8CaAl2Si2O6] par-ticles bound together by carbonate or clay miner-als. Silicate minerals do not react with HCl; they respond instead to stimulation uids that contain hydrouoric acid [HF] or uoboric acid [HBF4].1

Despite the uid chemistry differences, the engi-neering aspects of carbonate and sandstone acidizing are largely similar. However, this article concentrates on recent advances that are partic-ularly relevant to carbonate acidizing.

Carbonate Acidizing FundamentalsLimestone and dolomite rapidly dissolve in HCl, forming water-soluble reaction productsmainly calcium and magnesium chloridesand liberating carbon dioxide. The dissolution rate is limited by the speed at which acid can be delivered to the rock surface. This dissolution process results in rapid formation of irregularly shaped channels called wormholes (above right).Wormholes radiate outward in a dendritic pat-tern from points where acid leaves the well and enters the formation. Once formed, they become the most permeable pathways into the formation and carry virtually all of the uid ow during pro-duction. For efcient stimulation, the wormhole network should penetrate deeply and uniformly throughout the producing interval.

Achieving stimulation uniformity can be par-ticularly challenging when large permeability variations exist within the treatment interval. As acid penetrates the formation, it ows preferen-tially into the most-permeable pathways. Higher-permeability areas receive most of the uid and become larger, causing the treatment uids to bypass lower-permeability regions where stimu-lation is needed most. To address this problem, engineers and chemists have developed methods

to divert acidizing uids away from high-permea-bility intervals and into less permeable zones.

Engineers accomplish diversion by employing mechanical or chemical means or both.2

Mechanical diversion of treatment uids may be achieved using drillpipe or coiled tubingcon-veyed tools equipped with mechanical packers that isolate and direct uid into low-permeability zones. Alternatively, ow can be blocked at indi-vidual perforations by dropping ball sealers into

> Acid-induced wormholes. An intricate network of wormholes formed during a laboratory-scale matrix acidizing treatment of a carbonate formation sample. The length, direction and number of wormholes depend on the formation reactivity and the rate at which acid enters the formation. Once formed, the wormholes may carry virtually all of the uid ow during production.

6 Oileld Review

the stimulation uid as it travels down the well.The ball sealers are drawn to and seat againstperforations accepting the most uid. After thetreatment, the ball sealers fall away, are mechan-ically dislodged or dissolve (above).

Chemical diverting agents incorporated instimulation uids may be divided into two catego-riesparticulates and viscosiers. Particulatesinclude plugging agents such as benzoic acidakes and salt grains that are sized to plug forma-tion pores. Foaming the acid may achieve a simi-lar plugging effect because of two-phase ow.

Viscosiers include water-soluble polymers,crosslinked polymer gels and viscoelastic surfac-tants (VESs).3 A decade ago, Schlumberger scien-tists and engineers applied VES chemistry to acidstimulation and introduced the VDA viscoelastic

diverting acid system. VDA uids have been par-ticularly successful in both matrix and fractureacidizing applications around the world.4

The surfactant molecule in the VDA system,derived from a long-chain fatty acid, is zwitter-ionica neutral molecule that carries a positiveand a negative charge at separate positions.5

While being pumped down a well, VDA uidablend of HCl, VES and common acid-treatmentadditivesmaintains a low viscosity. As the acidis consumed in the formation, the surfactant mol-ecules begin to aggregate into elongatedmicelles.6 The micelles become entangled andcause the uid viscosity to increase (below). Thehigher-viscosity uid forms a temporary barrierthat forces fresh acid to ow elsewhere. In addi-tion to providing diversion, the viscosity decreases

the rate at which the acid reacts with the forma-tion, thereby allowing more time for the creationof deeper and more intricate wormholes.

When production begins, VDA uid is exposedto hydrocarbons, which alters the ionic environ-ment and causes the micelles to become spheri-cal. Entanglement ceases, the micelles roamfreely, and the uid viscosity decreases dramati-cally, enabling efcient poststimulation cleanup.Unlike polymer-base uids, VESs leave virtuallyno damaging residue behind that may interferewith well productivity.

Naturally fractured reservoirs are the mostchallenging environments for carbonate acidiz-ing because they can present extreme permeabil-ity contrasts. The fractured regions may beseveral orders of magnitude more permeablethan the unfractured layers. Until recently, theindustrys considerable portfolio of diversiontechnologies has been inefcient in this environ-ment. Even when using self-diverting uids suchas the VDA formulation, engineers struggled toblock the fractures and treat the rest of the for-mation. Consequently, operators were forced topump large volumes of uid to achieve stimula-tion, leading to higher treatment costs and lessthan optimal results.

However, Schlumberger engineers and chem-ists discovered that signicant diversion improve-ments could be achieved by adding degradablebers to VDA uid. As ber-laden diversion uidenters a fracture, the bers congregate, entangleand form structures that limit uid entry. Thenew product, MaxCO3 Acid degradable diversionacid system, has been used successfully and ef-ciently to stimulate notoriously difcult carbon-ate reservoirs around the world.

>Mechanical diversion methods. Ball sealers (green spheres) are pumped down the well during thestimulation treatment (left). The balls provide mechanical diversion because they preferentially blockthe perforations that take the highest volume of treatment uid. Straddle packers may also be deployedon coiled tubing to isolate the preferred treatment interval (right). In this example, engineers havealready stimulated the bottom zone and moved the packers up in preparation for stimulating the next zone.

Ball Sealers Straddle Packers

> Viscoelastic surfactant (VES) uid behavior during an acidizing treatment. Initially, when the surfactant is dispersed in acid, each molecule movesindependently throughout the uid (left). As the acid reacts with the carbonate minerals, the surfactant molecules assemble and create elongated micelles(center). The micelles entangle and hinder uid ow, resulting in higher uid viscosity. When hydrocarbon production begins after the treatment, theelongated micelles transform into spheres (right), resulting in a dramatic decrease in uid viscosity and facilitating efcient cleanup.

Surfactantmolecules

Elongated micelles Spherical micelles

Spent acid Hydrocarbon

CaCO3 + 2HCl CaCl2 + CO2 + H2O

Autumn 2013 7

This article describes the development of theMaxCO3 Acid system in the laboratory and itsintroduction to the oil eld. Case histories fromMexico, Saudi Arabia and Brazil demonstratehow application of this new acid system is achiev-ing signicant well productivity improvements.

Studying Fiber-Laden Acids in the LaboratoryFor more than 20 years, chemists and engineershave explored ways in which bers could be usedto improve well servicing operations. Working

with both mineral- and polymer-base bers, theydiscovered techniques for controlling the behav-ior of uids and suspended solids, both duringand after placement in a well. The researchresulted in several innovations, including meth-ods for limiting lost circulation during drillingand cementing, improving the exibility anddurability of well cements, aiding proppant trans-port during hydraulic fracturing operations andpreventing proppant owback into the well aftera fracturing treatment.

Studying applications for bers in the contextof acidizing has been a more recent endeavor. In2007, scientists at Schlumberger began exploringthe ability of bers to improve uid diversion inboth openhole and cased hole scenarios (above).The principal difference between the two condi-tions is that, for openhole completions, bersmust accumulate along the entire wellbore sur-face to provide diversion, but in a cased holesituation, ber deposition may be conned toperforations.

The engineers discovered that simply addingbers to a conventional HCl solution failed to cre-ate a stable brous suspension. Shortly afteraddition, the bers congregated, formed clumpsand separated from the acid. Success wasachieved by adding bers to VDA uid. The resul-tant higher uid viscosity allowed the creation ofa robust suspension of discrete bers.

3. For more on water-soluble polymers and VESs: Gulbis Jand Hodge RM: Fracturing Fluid Chemistry andProppants, in Economides MJ and Nolte KG (eds):Reservoir Stimulation, 3rd ed. Chichester, West Sussex,England: John Wiley & Sons, Ltd (2000): 7-17-23.

4. Al-Anzi E, Al-Mutawa M, Al-Habib N, Al-Mumen A,Nasr-El-Din H, Alvarado O, Brady M, Davies S, Fredd C,Fu D, Lungwitz B, Chang F, Huidobro E, Jemmali M,Samuel M and Sandhu D: Positive Reactions inCarbonate Reservoir Stimulation, Oileld Review 15,no. 4 (Winter 2003/2004): 2845.Lungwitz B, Fredd C, Brady M, Miller M, Ali S andHughes K: Diversion and Cleanup Studies of Viscoelastic

> Fiber deposition and diversion scenarios. During openhole acidizing (top and bottom left), bers forma ltercake that covers the entire wellbore wall. During cased hole acidizing (top and bottom right),bers form ltercakes in the perforation tunnels.

Wellborewall

Openhole Acidizing Cased Hole Acidizing

Well Well

Casing

Filtercake

Filtercake

FiltercakeTreatment fluid Treatment fluid

Filtercake

Wormhole

Wormhole Perforation

Perforation

Casing

Surfactant-Based Self-Diverting Acid, SPE Production &Operations 22, no. 1 (February 2007): 121127.

5. Sullivan P, Nelson EB, Anderson V and Hughes T: OileldApplications of Giant Micelles, in Zana R and Kaler EW(eds): Giant MicellesProperties and Applications.Boca Raton, Florida, USA: CRC Press (2007): 453472.

6. A micelle is a colloidal assembly of surfactant molecules.In the aqueous environment of an acidizing uid, thesurfactant molecules are arranged such that the interiorof the micelle is hydrophobic and the exterior ishydrophilic. Worm-like micelles may be microns long andhave a cross section of a few nanometers.

8 Oileld Review

The engineers then began performing exper-iments with laboratory-scale equipment forsimulating uid leakoff and ber deposition(above). The principal simulator was a bridgingapparatus that accommodated a variety of ori-ces through which ber-laden acid could passat various ow rates. Circular orices, withdiameters between 1 and 2 mm [0.04 and0.08 in.], simulated wormholes. Rectangular ori-ces with widths between 2 and 6 mm [0.08 and0.24 in.] were analogous to fractures. Engineersobserved ber plug formation and recorded thecorresponding system pressure as ber-ladenacid passed through an orice.

> Laboratory-scale equipment for testing leakoff behavior and ltercake deposition. Engineers used a conventional ltration cell to simulate an openholestimulation (top). Technicians rst placed a carbonate core at the bottom of the cell and then poured in ber-laden acid. After sealing the cell, they applieddifferential pressure across the core and used a balance to measure the amount of ltrate passing though the core. For the cased hole simulation (bottom),engineers used a bridging apparatus. The apparatus consisted mainly of a 300-mL tube tted with a piston, a high-performance liquid chromatography(HPLC) pump and an orice (left). The orice could be circular to simulate a wormhole (top right) or rectangular to mimic a fracture (bottom right).Technicians installed a piston at the top of the tube, which contained ber-laden acid. Acid exiting the tube passed through the orice, and the techniciansassessed the diversion capability of bers by measuring the ltrate volume, the ber ltercake volume and the pumping pressure at various ow rates.

Pressure

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d flo

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2 cm

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Wormhole Geometry

Fissure or Fracture Geometry

Acidand fibers

Cased Hole Simulation

Pressure evolution in the apparatus followeda consistent pattern (next page, top left).Initially there was no pressure increase, butwithin a few seconds, the pressure rose rapidlyas the bers formed a bridge and began to llthe orice. These results indicated that as earlyvolumes of ber-laden acid reach the perfora-tions, the acid penetrates the reservoir as if nobers are present. Then, as the bers bridge,they accumulate inside the perforations andform a ltercake. Next, the bers plug theperforation, decreasing injectivity and promot-ing uid diversion into other perforations.The engineers also discovered that the ber

concentration required to achieve bridgingincreased with the uid injection rate (nextpage, top right).

In the laboratory, after pumping the ber-laden acid through the orice, engineers per-formed a freshwater ush. As the viscous acidleft the apparatus, the pumping pressure gradu-ally decreased and eventually stabilized. At theend of each test, a stable ber plug remained inthe orice. Knowing the pressure, ow rate,uid viscosity and ber plug length, engineerswere also able to use Darcys law to calculatethe ber plug permeabilities. Depending on theber concentration and the uid ow rate dur-

Autumn 2013 9

7. It may appear counterintuitive to imagine that ber plugswith permeabilities higher than that of the formationcould provide signicant diversion. However, signicantdiversion is also provided by the ow restriction andpressure drop as uid enters the perforations.

8. Cohen CE, Tardy PMJ, Lesko T, Lecerf B, Pavlova S,Voropaev S and Mchaweh A: Understanding Diversionwith a Novel Fiber-Laden Acid System for MatrixAcidizing of Carbonate Formations, paper SPE 134495,presented at the SPE Annual Technical Conference andExhibition, Florence, Italy, September 1922, 2010.

> Pressure-versus-time plot from a slot-ow experiment. During thisexperiment, the MaxCO3 Acid composition consisted of 15 wt% VDA uid and6 kg/m3 (50 lbm/1,000 galUS) degradable bers. In Period 0, MaxCO3 Acid uidbegins owing through the slot, and the bers have not yet formed a bridge.In Period 1, the pressure rises as the bers entangle and form a plug in theslot. Pressure continues to climb until the volume of acid is exhausted. InPeriod 2, the pressure gradually falls as freshwater enters the slot anddisplaces the viscous acid. The system pressure stabilizes during Period 3.The white ber plug remains intact and stable inside the slot (photograph).

Pres

sure

, psi

40

50

60

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Time, s40 50 60 70 80

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ing ber deposition, the measured permeabili-ties varied between 400 and 2,400 mD. Thesedata led engineers to conclude that bers wouldprovide the most efcient diversion in zoneswith permeabilities exceeding 100 mD (left).7

The data acquired during the simulator exper-iments also allowed scientists to develop a math-ematical model for predicting the behavior ofber-laden acids under openhole and cased holeconditions; the model may be used to optimizetreatment designs.8 They performed 340 ne-scale3D simulations that evaluated typical perforationschemes, brous ltercake permeabilities andformation permeabilities. The resulting modelallows scientists to track the movement of the u-ids and bers through the wellbore and into thereservoir and track the propagation of wormholesgenerated as the acid reacts with carbonate rock.

> Effect of degradable ber concentration onbridging ability in a slot. During the slot-owexperiments, engineers determined that the berconcentration required to achieve bridging andpromote uid diversion increases with the uidinjection rate.

Linear fluid velocity, m/min

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30251550 2010

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> Apparent permeability resulting from plugging a perforated zone withbers. The x-axis shows the original core permeability. The y-axis shows theapparent zone permeability after a brous ltercake with a permeability of2 D has formed. The results show that after plugging occurs, when corepermeability exceeds about 1 mD, apparent permeability eventually levels offat about 100 mD and becomes independent of core permeability.

Appa

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10 Oileld Review

> Diversion predictions from the MaxCO3 Acid simulator. During ber deposition experiments in the perforation simulator, the permeabilities of the resultingber plugs varied between about 400 and 2,400 mD (left). The simulator predicts how the ber plugs decrease the apparent permeabilities of reservoirs andpromote diversion. Lower-permeability ber plugs are more efcient diverters. Modeling studies also demonstrated that brous ltercakes provide uiddiversion by equalizing the permeabilities of layers in the treated interval. For example, if the interval contains four layers with various permeabilities, theuid ow rate into the more permeable layers decreases and the uid ow rate into the less permeable layers increases. Eventually, the ow ratesconverge to a single ow rate, and the interval behaves as if it has a single permeability (right). Flow rate convergence occurs more quickly in a cased holewith perforations because the ltercake surface area is lower.

Appa

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Layer permeability30 D10 D3 D1 D

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>MaxCO3 Acid uid batch mixing. The degradable bers (top left) are light and nely divided, presenting a mixing challenge. Traditional equipment forbatch mixing of acidizing uids was inefcient. Engineers discovered that equipment for batch mixing cement slurries (bottom left) could disperse the bersin VDA uid. The VDA uid ows into an 8,000-L [50-bbl] paddle mixer (top right). To avoid the formation of clumps, eld personnel manually add bers to theuid. After the bers have been added, the tank is lled with more VDA uid, and agitation continues until the mixture reaches a uniform consistency(bottom right). During the job, engineers maintain the agitation to preserve uid uniformity.

Autumn 2013 11

9. For more on formation damage testing in the laboratory:Hill DG, Litard OM, Piot BM and King GE: FormationDamage: Origin, Diagnosis and Treatment Strategy, inEconomides MJ and Nolte KE (eds): ReservoirStimulation, 3rd ed. Chichester, West Sussex, England:John Wiley & Sons, Ltd (2000): 14-3114-33.

> Behavior of degradable bers. Engineers performed static bottle tests during which degradablebers were immersed in partially spent HCl uids. The data show that the rate of ber dissolutiondecreases as the HCl becomes neutralized. Nevertheless, complete ber dissolution occurs within afew days (top). Core testing demonstrated that the acidic ber degradation products may furtherstimulate the formation (bottom). Using a standard core testing apparatus at 115C [239F], engineerspumped 2% KCl solution into a limestone core rst in the injection direction and then in the reverse, orproduction, direction (K0 and K1). Technicians recorded the pressure across the core and, applyingDarcys law, determined that the initial core permeability was 5.1 mD. Next, they injected a partiallyspent 20% HCl uid (pH = 6.5) containing degradable bers (N2). Subsequent pumping of 2% KCl in bothdirections revealed that the core permeability had fallen to 3.5 mD (K2 and K3). Following a 16-h shut-inperiod, the bers had begun to degrade, and the core permeability rose to about 4.8 mD (K4 and K5).After another 16-h shut-in period, complete ber degradation had occurred, and the core permeabilityrose to 5.5 mD (K6 and K7)an 8% improvement over the initial permeability of 5.1 mD.

Fibe

r deg

rada

tion

time,

hVolume of acid spent at 100C, %

20

20 30 40 50 60 70 80 90 100100

40

60

80

100

120

0Pe

rmea

bilit

y, m

D

Fluid volume, pore volumes

2% KCI (injection direction)2% KCI (production direction)Fibers injected with spent acid (pH = 6.5)

16-hshut-in

K0 K1

K2K3

K4K5

K6K7

N2

16-hshut-in

10

9

8

7

6

5

4

3

2

1

00 5 10 15 20 25 35 45 50 5530 40

In addition, the model predicts uid diversionbehavior (previous page, top).

After demonstrating the diversion capabili-ties of ber-laden VDA uids in the laboratory,the developers considered the effects of bers onreservoir productivity following an acidizingtreatment. If bers remained in the wormholesindenitely, their presence would hinder the owof uids from the reservoir to the wellbore. Forthis reason, degradable bers were viewed as anattractive option. After a treatment, the bershydrolyze and degrade within a few days. Theabsence of bers leaves unobstructed wormholesand maximizes formation productivity. Further-more, the degradable bers are composed of anorganic acid polymer whose degradation prod-ucts are acidic, giving rise to further formationstimulation (right).9

The results of the laboratory study were suf-ciently encouraging to allow the engineers toadvance to the next development stageyardtesting to demonstrate that the ber-ladenMaxCO3 Acid uid could be prepared and pumpedefciently and safely.

Verifying Wellsite DeliverabilityBecause matrix acidizing treatments typicallyconsume small uid volumes compared withother stimulation techniques, engineers usuallyemploy batch-mixing procedures. By contrast,fracture acidizing usually requires large uid vol-umes, and continuous mixing is necessary tokeep pace with the higher pump rates.Consequently, engineers needed to developmethods for mixing MaxCO3 Acid formulations inboth scenarios. The principal objectives were todisperse the bers safely and efciently in theuid and prepare a uniform suspension. Becausethe degradable bers are light and nely divided,engineers were challenged to devise ways toimmerse the bers in the VDA uid so that theywould form a homogeneous mixture.

Experimentation led to the discovery thatuniform MaxCO3 Acid mixtures can be efcientlybatch mixed with existing equipment (previouspage, bottom). The equipment consists of a ves-sel, into which engineers pour the base VDA uid,and an 8,000-L [50-bbl] recirculating mixing tankequipped with rotating paddles. Field personneldispense the bers manually. Until the treatmentcommences, continuous agitation prevents berand uid separation.

The POD programmable optimum densityblender is standard Schlumberger equipment forcontinuously dispensing solid materials such asproppant into fracturing uids, and it proved to

be an efcient system for preparing MaxCO3 Acidmixtures. However, the uid exit points must besecure to ensure that personnel are shieldedagainst uid leaks and sprays. Therefore, engi-neers designed a special splash protection kit

12 Oileld Review

10. Bullheading is the pumping of uids into a wellbore fromthe surface with no direct control over which intervalswill accept the uids.

11. Thabet S, Brady M, Parsons C, Byrne S, Voropaev S,Lesko T, Tardy P, Cohen C and Mchaweh A: Changingthe Game in the Stimulation of Thick Carbonate GasReservoirs, paper IPTC 13097, presented at theInternational Petroleum Technology Conference,Doha, Qatar, December 79, 2009.

that includes a berm below the blender and aplastic sidewall (above left). They also developeda special chute for metering the degradablebers as they are dispersed into the mixing tub.The modied chute, mounted directly above themixing tub, has no restrictions or bends thatmight hinder smooth ber delivery.

After verifying that MaxCO3 Acid uids couldbe prepared reliably with existing eld equip-ment, the project team traveled to Qatar foreld testing. A principal test objective was toevaluate the accuracy of the acid placement anddiversion simulator.

Field Testing in QatarThe North eld in Qatar is an offshore gas pro-ducer that presents unique challenges for com-pletion and stimulation (above right). Thereservoir is 1,000 to 1,300 ft [300 to 400 m] thickand the wells, which may be deviated by as muchas 55, can be as long as 2,000 ft [610 m]. The res-ervoir comprises alternating sequences of lime-

> Continuous mixing of MaxCO3 Acid uid. A POD blender is outtted with aspecial ber delivery feeder (top right) that has no restrictions or bends,thus ensuring smooth metering. Field workers place a berm (top left) underthe blender to guard against uid spills. A plastic sidewall around the mixingtubs (bottom) further shields the mixing process.

Fiber feeder

> Qatar North eld. Discovered in the 1970s, this accumulation is the largestgas eld in the world, with estimated reserves as high as 25.5 trillion m3[900 Tcf]. The reservoir is called the South Pars eld on the Iranian side ofthe maritime border (dashed black line). The producing formation ischaracterized by large interzonal permeability contrastsup to a ratio of100:1. The reservoir depth is about 3,000 m [9,800 ft] below the seabed, andthe elevated hydrostatic pressure tends to favor stimulation of bottomzones at the expense of upper reservoir layers, further increasing thedifculty of achieving uniform stimulation in one treatment.

IRAN

QATAR

BAHRAINNorthField

SouthPars

SAUDIARABIA

0 km

0 mi 50

50

SAUDIARABIA

IRAN

> Jujo-Tecominoacn eld. This region is among the most prolic oil and gas producing areas insouthern Mexico. The reservoirs are naturally fractured and difcult to stimulate uniformly.

Villahermosa

TabascoState

Jujo-Tecominoacn Field

50

km0 50

miles0

UNITED STATES

MEXICO

Autumn 2013 13

stone and dolomite that have a permeabilitycontrast ratio as high as 100:1.

The typical workow for designing and per-forming a MaxCO3 Acid treatment consisted ofseveral steps. To build a reservoir model, engi-neers rst acquired a thorough description of thecandidate well. The description included wellcompletion diagrams, petrophysical and pressurelog measurements and pretreatment well pro-duction data. The simulator produced a pumpingschedule designed to provide optimal zonal cov-erage and maximize posttreatment reservoir per-meability. During the treatment, engineersmeasured the bottomhole and wellhead pres-sures and compared the results with those pre-dicted by the simulator. Posttreatment activitiesincluded production logging to further verify theaccuracy of the simulator.

One test well had 290 ft [88 m] of perforationsalong 830 ft [250 m] of measured depthbetween 12,270 and 13,100 ft [3,740 and 3,990 m].The principal obstacles to effective acid place-ment were the high permeability contrast andhydrostatic pressure effects favoring preferentialstimulation of deeper high-permeability zones(right). Prior to these eld tests, installation ofbridge plugs had been the preferred technique toachieve uid diversion.

Schlumberger engineers performed a matrixacidizing treatment from a stimulation vesselusing the bullheading technique.10 The treatmentconsisted of alternating stages of 290 bbl [46 m3]of 28% HCl and 320 bbl [51 m3] of MaxCO3 Aciduid containing 75 lbm/1,000 galUS [9.0 kg/m3]of degradable bers. To ensure uniform ber sus-pension, engineers set up the treatment so that160-bbl [25-m3] spacers of VDA uid precededand followed the MaxCO3 Acid stages. During thetreatment, the simulated and measured bottom-hole pressures were in good agreement, provid-ing conrmation that the diversion physics ofMaxCO3 Acid behavior were well described by thesimulator (right).

After the success of the rst test well, engi-neers performed 10 more acidizing treatments inthe eld with similar results.11 The ber-ladenacid performed as predicted, and operationalefciencies were gained by not having to rely onmechanical diversion. The time required to com-plete, perforate, stimulate and clean up theMaxCO3 Acid wells was two to four days shorterthan that of the traditional approach, represent-ing a savings of US$ 480,000 to US$ 960,000 perwell. Environmental benets included a 72%reduction in the emission of greenhouse gasesbecause of reduced aring. Following the successof the Qatari eld tests, the operator deployedMaxCO3 Acid technology in other regions.

> Permeability prole. The permeability varies four orders of magnitude in atest well in the Qatar North eld.

Mea

sure

d de

pth,

ft

Permeability, mD

13,2000.1 1 10 100 1,000

13,100

13,000

12,900

12,800

12,700

12,600

12,500

12,400

12,300

12,200

> Simulated and measured pressures from a eld test in the Qatar North eld. Engineers pumped fourstages of 28% HCl and MaxCO3 Acid uid. A VDA uid spacer preceded and followed each MaxCO3Acid stage to preserve ber suspension uniformity. The excellent agreement between the measured(blue curve) and simulated (black) bottomhole pressures (BHP) helped conrm the validity of theMaxCO3 Acid placement model.

6,500

7,500

6,000

7,000

8,000

5,500

5,00080 100 120 140 160

25

35

30

40

20

15

10

50

BHP,

psi

Time, min

Pum

p ra

te, b

bl/m

in

Measured BHPSimulated BHPPump rate

Fluid at perforationsMaxCO3 Acid fluidWater

GasHCIVDA acid

Optimizing Production in Southern MexicoThe Jujo-Tecominoacn eld, operated byPetrleos Mexicanos (PEMEX), is located 60 km[40 mi] from Villahermosa, Tabasco, in southern

Mexico (previous page, bottom). The eld has48 producing wells and 19 injection wells tomaintain reservoir pressure. The average depthof the producing intervals is 5,000 m [16,400 ft],

14 Oileld Review

and the reservoir temperature varies between120C and 160C [250F and 320F]. Wells in thiseld typically produce from multiple perforatedintervals with a highly variable natural fracturedensity. This scenario creates a large permeabil-ity contrast between intervals that can reach1,000:1. Consequently, achieving uniform zonal

coverage during stimulation treatment presentsa major challenge.

One typical well that was drilled in 2005 hastwo producing intervals: from 5,274 to 5,294 m[17,303 to 17,369 ft] and from 5,308 to 5,340 m[17,415 to 17,520 ft]. The reservoir temperatureand pressure are 137C [279F] and 22.8 MPa

[3,300 psi]. Porosity varies between 5% and 8%.The permeabilities of the upper and lower inter-vals are 1,000 mD and 3 mD; therefore, the per-meability contrast is 333:1.

The initial oil production rate was 1,278 bbl/d[203 m3/d]. Between 2006 and 2009, PEMEX per-formed several stimulation treatments using con-ventional acids and diversion techniques. Theproduction rate increased immediately aftereach treatment but failed to stabilize and contin-ued to decline. In 2009, PEMEX engineersdecided to evaluate the MaxCO3 Acid technologyin the hope of achieving uniform and long-lastingstimulation of the two intervals.12

Schlumberger engineers performed a matrixacidizing treatment consisting of bullheading30 m3 [7,800 galUS] of aromatic solvent preush toclean the perforations, 60 m3 [15,600 galUS] ofHClformic acid blend, 10 m3 [2,600 galUS] ofMaxCO3 Acid uid containing 90 lbm/1,000 galUS[11 kg/m3] bers and 2 m3 [520 galUS] of ammo-nium chloride brine spacer (above left). Pumprates varied between 8.2 and 15 bbl/min [1.3 and2.4 m3/min]. The last treatment stage containednitrogen to energize the uid and accelerate wellcleanup, and hydrocarbon production commencedwithin three days. The initial oil production rate,3,000 bbl/d [480 m3/d], exceeded PEMEXs fore-cast. After three months, the average oil produc-tion rate had stabilized at 1,600 bbl/d [250 m3/d](below left). Following the success of this treatment,PEMEX has continued to apply MaxCO3 Acid tech-nology in this eld with favorable results.

> Pumping schedule for a matrix acidizing treatment in the Jujo-Tecominoacn eld. During the 11-stage treatment, engineers pumped anaromatic solvent to clean up perforations, an HClformic acid blend,MaxCO3 Acid uid and an ammonium chloride brine spacer. The nal stagecontained nitrogen [N2] to enhance well cleanup.

Fluid NameStage Name Stage FluidVolume, m3Nitrogen Pump

Rate, m3/min

Spacer 3% NH4Cl brine

Spacer 3% NH4Cl brine

Diverter MaxCO3 Acid fluid

Diverter MaxCO3 Acid fluid

Acid HCIformic acid blend

HCIformic acid blend

HCIformic acid blend

Acid

Preflush Aromatic solvent

Preflush Aromatic solvent

Preflush Aromatic solvent

Acid

1

1

5

5

20

20

10

10

10

20

Flush Nitrogen

80

80

150

> Production history in a PEMEX well in the Jujo-Tecominoacn eld. Initial oil production was1,278 bbl/d [203 m3/d]. Subsequent matrix acidizing treatments employing conventional techniquesfailed to achieve sustained production improvements. After a MaxCO3 Acid treatment in December2009, oil production increased to 3,000 bbl/d and stabilized at 1,600 bbl/d, exceeding the originalproduction rate.

Oil p

rodu

ctio

n ra

te, b

bl/d

Date

Begin MaxCO3 Acid treatment

Oil production

Jan 2009 Jan 2010Apr 2009 Apr 2010July 2009 Oct 2009

2,000

2,500

3,000

3,500

1,500

1,000

500

0

12. Martin F, Quevedo M, Tellez F, Garcia A, Resendiz T,Jimenez Bueno O and Ramirez G: Fiber-AssistedSelf-Diverting Acid Brings a New Perspective to Hot,Deep Carbonate Reservoir Stimulation in Mexico,paper SPE 138910, presented at the SPE Latin Americanand Caribbean Petroleum Engineering Conference,Lima, Peru, December 13, 2010.

13. Rahim Z, Al-Anazi HA, Al-Kanaan AA and Aziz AAA:Successful Exploitation of the Khuff-B Low PermeabilityGas Condensate Reservoir Through OptimizedDevelopment Strategy, Saudi Aramco Journal ofTechnology (Winter 2010): 2633.

14. Aviles I, Baihly J and Liu GH: Multistage Stimulationin Liquid-Rich Unconventional Formations,Oileld Review 25, no. 2 (Summer 2013): 2633.

15. Jauregui JL, Malik AR, Solares JR, Nunez Garcia W,Bukovac T, Sinosic B and Grmen MN: SuccessfulApplication of Novel Fiber Laden Self-Diverting AcidSystem During Fracturing Operations of NaturallyFractured Carbonates in Saudi Arabia, paperSPE 142512, presented at the SPE Middle East Oil andGas Show and Conference, Manama, Bahrain,September 2528, 2011.

Autumn 2013 15

> South Ghawar eld in eastern Saudi Arabia. The producing reservoirs, in the Khuff Formation, arecomposed of heterogeneous carbonates. The permeability and porosity vary widely within 100 to 200 ft[30 to 60 m] of formation thickness, presenting difcult uid diversion challenges.

IRAN

BAHRAIN

QATAR

UNITED ARABEMIRATES

SAUDI ARABIA

South Ghawar Field

0 km

0 mi 100

100

GasOil

SAUDIARABIA

EGYPT

IRAN

Improving Gas Production in Saudi ArabiaThe vast carbonate reservoirs of Saudi Arabia areprime locations for stimulation treatments usingacidic uid systems. From simple acid washes tomajor acid fracturing operations, every carbon-ate stimulation technology has found an applica-tion in this region.

Most gas production in Saudi Arabia comesfrom the Khuff Formation, located in the easternpart of the country (right). The Khuff Formationis highly heterogeneous, exhibiting wide varia-tions in formation permeability (0.5 mD to10 mD) and porosity (5% to 15%). It is composedmainly of calcite and dolomite interbedded withstreaks of anhydrite. The average temperatureand pressure are 280F [138C] and 7,500 psi[52 MPa].13

Saudi Aramco engineers applied MaxCO3 Acidtechnology during several matrix acidizingtreatments, all of which yielded excellentresults. Following this success, Saudi Aramcoengineers decided to perform 25 acid fracturingtreatments employing the MaxCO3 Acid formu-lation. Eight acid fracturing stages were per-formed in three wells equipped with openholemultistage fracturing completions that enabledcontinuous treatments.14 The remainder of thejobs, single-stage treatments in vertical or devi-ated wells, were completed with cemented andperforated liners.15

Engineers performed one treatment in acemented and perforated well that had a 65deviation. Three pay zones existed along a 240-ft[73-m] interval in the central sector of the eld.From reservoir parameters obtained from open-hole logs, engineers concluded that, to meetSaudi Aramcos production expectations, it wouldbe necessary to pump a treatment that stimu-lated all three perforated zones simultaneously.

Engineers developed a fracturing treatmentthat consisted of 19 uid stages that alternatedportions of a 35-lbm/1,000 galUS [4.2-kg/m3]borate crosslinked guar fracturing uid, 28% SXEsuperX emulsied acid to retard the rate of acidconsumption, 28% HCl and 15% MaxCO3 Acid for-mulation with degradable ber concentrationsbetween 75 and 175 lbm/1,000 galUS [9 and21 kg/m3] (right). During the treatment, after therst MaxCO3 Acid stage contacted the formation,engineers recorded a 4,500-psi [31-MPa] bottom-hole pressure risethe rst time such a largeincrease had been recorded in this carbonatereservoirindicating that excellent uid leakoff > Pumping schedule for an acid fracturing treatment in Saudi Arabia. The total uid volume was

124,200 galUS [2,960 bbl, 470 m3], allowing simultaneous stimulation of three zones without the need formechanical diversion techniques. Such treatment simplicity saved several days of rig time, resulting insignicant operational cost savings.

Treatment Schedule

Fluid NameStage Name Stage FluidVolume, galUS [m3]Acid

Concentration, %Pump Rate,

bbl/min [m3/min]

20 [3.2]

30 [4.8]

40 [6.4]

40 [6.4]

40 [6.4]

30 [4.8]

35 [5.6]

30 [4.8]

35 [5.6]

40 [6.4]

20 [3.2]

30 [4.8]

40 [6.4]

40 [6.4]

10 [1.6]

10 [1.6]

10 [1.6]

10 [1.6]

40 [6.4]

0

0

0

0

0

0

0

15

15

15

28

28

28

28

0

0

15

28

0

Pad

Pad

Pad

Pad

Pad

Pad

Pad

Diverter 1

Diverter 2

Diverter 3

Acid 1

Acid 2

Acid 3

Acid 3

Overflush 2

Flush

Diverter 4

Acid 4

Overflush 1

Crosslinked 35-lbm gel

Crosslinked 35-lbm gel

Crosslinked 35-lbm gel

Crosslinked 35-lbm gel

Crosslinked 35-lbm gel

Crosslinked 35-lbm gel

Crosslinked 35-lbm gel

MaxCO3 Acid fluid

MaxCO3 Acid fluid

MaxCO3 Acid fluid

SXE emulsified acid

SXE emulsified acid

SXE emulsified acid

SXE emulsified acid

Overflush

Water

MaxCO3 Acid fluid

28% HCl

Overflush

9,000 [34]

9,000 [34]

9,000 [34]

3,000 [11]

10,000 [38]

3,000 [11]

3,000 [11]

3,000 [11]

3,000 [11]

9,000 [34]

9,000 [34]

9,000 [34]

9,000 [34]

5,000 [19]

11,200 [42]

3,000 [11]

7,000 [26]

7,000 [26]

3,000 [11]

16 Oileld Review

> Pressure and temperature data. During a Saudi Aramco acid fracturing treatment, the pumping rate(blue line) varied from 10 to 40 bbl/min [1.6 to 6.4 m3/min], and the bottomhole treating pressure (redline) exceeded the formation fracturing pressure (dashed black line) throughout most of the treatment.The vertical blue bars denote periods during which MaxCO3 Acid uid entered the perforations.

8,000

6,600

5,200

3,800

2,400

1,000

10

10 30 50 70 90 110 130 150 170

25

40

55

70

85

100

115

9,400

10,800

12,200

15,000

13,600

Pres

sure

, psi

Treatment time, min

Fracturing pressure

Rate

, bbl

/min

10

1Bottomhole treating pressurePump rate

> The presalt reservoirs of Brazil. The main producing elds are located primarily offshore (left). The reservoirs are in carbonate formations that lieunderneath a thick layer of evaporite minerals (right). The reservoir depth is between 4,500 and 6,500 m [14,800 and 21,300 ft].

BRAZIL

Salt

Dept

h, m

0

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

9,000

Overburden formations

Presaltoil

Rio de Janeiro

Espirito SantoBasin

Campos Basin

Santos Basin

So Paulo

Curitiba

SOUTHAMERICA

km 5000

mi 5000

control and diversion had been achieved (left).Moreover, the bottomhole pressure exceeded thefracturing pressure throughout most of the treat-ment, which had not been possible to achieveduring previous attempts using conventionaldiversion techniques.

After the treatment, the well cleaned up inless than three days; previously, four to ve dayshad been necessary. Prior to the treatment, thegas production rate had been 8 MMcf/d[230,000 m3/d] with a wellhead pressure of2,060 psi [14.2 MPa]. The posttreatment produc-tion rate was 23 MMcf/d [650,000 m3/d]anearly threefold increasewith a wellhead pres-sure of 2,230 psi [15.4 MPa]. The excellent post-stimulation performance of this well has beenobserved in the majority of other wells in thisregion treated with the ber-laden acid.

Elimination of mechanical diversion tech-niques reduced the well completion and stimula-tion time up to six days, resulting in a savings ofUS$ 480,000 to US$ 600,000. As a result, theMaxCO3 Acid system is now a prominent elementof Saudi Aramcos stimulation strategy.

Autumn 2013 17

>Matrix acidizing treatment. In a presalt well offshore Brazil, engineers pumped 13 uid stagesconsisting of alternating portions of 15% HCl, VDA diverter and MaxCO3 Acid uid at various pump rates(blue curve). A mixture of 15% HCl and a mutual solvent preceded and followed the treatment. As thetreatment progressed, the rig pressure (red curve) and bottomhole pressure (green curve) rose,indicating that the bers were effectively diverting treatment uid to zones with lower permeability.

0 1,00000

1,000

2,000

3,000

4,000

5,000

6,000

7,000

8,000

4

8

12

16

20

24

28

32

36

40

2,000 3,000

Time, s4,000

4,000

4,500

5,500

6,500

7,500

5,000

6,000

7,000

8,000

5,000 6,000 7,000 8,000 9,000 10,000

Pum

p ra

te, b

bl/m

in

Rig

pres

sure

, psi

Botto

mho

le p

ress

ure,

psi

HCl plus mutual solvent15% HClVDA fluidMaxCO3 Acid fluid

Stimulating Oil Production in Offshore BrazilIn South America, the presalt region comprisesa group of oil-bearing carbonate formationslocated in an offshore region along the coast ofBrazil (previous page, bottom).16 The produc-ing formations occur at depths between about4,500 and 6,500 m [14,800 and 21,300 ft] andlie directly underneath a 2,000-m [6,500-ft]layer of evaporite minerals. The reservoir tem-peratures vary between about 60C and 133C[140F and 272F].

The producing carbonate reservoir is a resultof the deposition of mollusks followed by diagen-esis. Such reservoirs, called coquinas, featurelarge variations in reservoir properties. Porosityvaries from 5% to 18%, and permeability variesfrom less than 0.001 mD to tens of mDs. Such het-erogeneity presents an especially difcult diver-sion challenge during stimulation treatments.

Engineers at Petrobras decided to evaluatethe MaxCO3 Acid ber-assisted diversion tech-nology in a new well in the Pirambu eld. Usingthe acid placement and diversion simulator,Schlumberger engineers designed a matrixacidizing treatment for an interval between4,500 m and 4,570 m [14,800 and 15,000 ft]. Thesimulator called for a 790-bbl [12.6-m3],13-stage bullheaded treatment consisting ofalternating volumes of 15% HCl, VDA uid andMaxCO3 Acid uid with a ber concentrationbetween 100 and 120 lbm/1,000 galUS [12 and14 kg/m3]. The treatment was preceded by abrine and HCl mixture containing a monobutylether mutual solvent.17 After the treatment,engineers pumped another volume of HCl withmutual solvent followed by diesel to acceleratewell cleanup. The pump rate varied from 5 bbl/min[0.8 m3/min] during the MaxCO3 Acid uidstages to 10 bbl/min [1.6 m3/min] during theinjection of HCl and to 20 bbl/min [3.2 m3/min]during the VDA diverter stages (above).

After well cleanup, engineers at Petrobrasevaluated the results by performing productionlogging. The logs showed that the well was pro-ducing from all of the treated zones as pre-dicted by the simulator. Since this treatment,

Petrobras has continued to specify the use ofMaxCO3 Acid fluid.

Rening MaxCO3 Acid TechnologyAs of this writing, more than 300 MaxCO3 Acidstimulation treatments have been performedaround the world. In addition to the examplesfeatured in this article, treatments have beenperformed in Kazakhstan, Angola, Canada, theUS, Kuwait and the Caspian Sea.

As the number of treatments has increased,the larger treatment database has allowed con-tinuous renement of the simulator and improve-ment of stimulation results in naturally fracturedcarbonate reservoirs. The technique has alsoallowed operators to reduce or eliminate the useof ball sealers or packers, thereby reducing costsand operational risks.

At present, work is underway to combineMaxCO3 Acid technology with the ACTive family oflive downhole coiled tubing services. This arrange-ment employs distributed temperature sensorsthat will allow engineers to monitor uid place-ment in real time and change treatment designsduring a job. Such exibility will further enhancethe effectiveness of acidizing treatments employ-ing ber-based uid diversion. EBN

16. Beasley CJ, Fiduk JC, Bize E, Boyd A, Frydman M,Zerilli A, Dribus JR, Moreira JLP and Pinto ACC:Brazils Presalt Play, Oileld Review 22, no. 3(Autumn 2010): 2837.

17. Mutual solvents are chemicals in which both aqueousand nonaqueous compounds are miscible. Thesesolvents may be used to prevent emulsions, reducesurface tension and leave formation surfaceswater-wet.

18 Oileld Review

Casing Corrosion Measurementto Extend Asset Life

Corrosion challenges are not new to the oil and gas industry, and producers are

continually seeking new ways to keep corrosion at bay. Experts have made advances

in corrosion monitoring along several fronts. The implementation of these technolo-

gies may help operators optimize infrastructure utilization, maximize production and

minimize negative impact on the environment.

Dalia AbdallahMohamed FahimAbu Dhabi Company for Onshore OilOperationsAbu Dhabi, UAE

Khaled Al-HendiMohannad Al-MuhailanRam JawaleKuwait Oil CompanyAhmadi, Kuwait

Adel Abdulla Al-KhalafQatar PetroleumDoha, Qatar

Zaid Al-KindiAbu Dhabi, UAE

Abdulmohsen S. Al-KuaitHassan B. Al-QahtaniKaram S. Al-YateemSaudi AramcoDhahran, Saudi Arabia

Nausha AsrarSugar Land, Texas, USA

Syed Aamir AzizJ.J. KohringDhahran, Saudi Arabia

Abderrahmane BenslimaniAhmadi, Kuwait

M. Aiman FituriDoha, Qatar

Mahmut SengulHouston, Texas

Oileld Review Autumn 2013: 25, no. 3.Copyright 2013 Schlumberger.For help in preparation of this article, thanks to Ram SunderKalyanaraman, Clamart, France.Avocet, EM Pipe Scanner, FloView, Petrel, PipeView,PS Platform, Techlog, UCI and USI are marks ofSchlumberger.

Oil and gas companies typically serve two mas-ters. On the one hand, protability dictates thatproducers maximize long-term production whileminimizing operating expenditures. On the other

hand, environmental compliance requires thatcompanies conduct exploration and productionoperations safely and in an environmentallyresponsible manner.

> Typical rening-corrosion life cycle for metals. Energy is stored in a metal as it is rened from itsnaturally occurring state (such as iron ore) to an alloy. Corrosion takes place spontaneously andreleases the stored energy, which returns the metal back to a lower energy state. That process can beslowed by the application of one or more eld-based mitigation measures.

Energy Added During Refining

Refined Metal or AlloyIron Ore (Oxides) and Corrosion Products

Energy Released by Corrosion

Autumn 2013 1919

The two mandates share a common enemy. Corrosion, which is the natural tendency for materials to return to their most thermodynami-cally stable state by reacting with agents in the surrounding environment, attacks almost every component of a well. Wells are constructed pri-marily of steel, which is rened from naturally occurring iron ore. The process of rening ore into a steel alloy suitable for oil and gas drilling and production takes the ore to a higher energy state. Corrosion reverses this process and brings metal back toward its original, lower energy state (previous page).1

The process of corrosion, which begins the moment steel is cast, is accelerated in the oil eld by the presence of acidic speciessuch as hydrogen sulde [H2S] or carbon dioxide [CO2]in many formation uids and by the elevated temperatures and pressures in producing forma-tions. The consequences of corrosion include a reduction in wall thickness and loss of strength, ductility and impact strength in the steel that makes up the downhole tubulars, wellheads and surface piping and downstream processing equip-ment (right).

Failure to address corrosive attacks early impacts well protability because operators must then implement potentially expensive, and per-haps extensive, mitigation methods. Not only does mitigation increase operating expenses, it may force operators to shut a well in for some period of time. In the worst cases, unattended corrosion can lead to a leak or rupture, which may threaten the safety of oileld personnel, lead to production losses and introduce hydrocarbons and other reservoir uids into the environment.

The total annual cost of corrosion in the US alone is estimated at approximately US$ 1.4 bil-lion, of which US$ 589 million is surface pipeline and facility costs, US$ 463 million is downhole tubing expenses and US$ 320 million is capital expenditures.2 These estimates do not factor in the nes that may be levied by government regu-latory agencies against operators that experience a corrosion-related discharge of production uids into the environment. The costs and risks may also increase as hydrocarbon sources are discovered in more-challenging environmentsdeeper reservoirs with higher temperatures and pressures that contain higher concentrations of

1. For more on the corrosion process: Brondel D, Edwards R, Hayman A, Hill D, Mehta S and Semerad T: Corrosion in the Oil Industry, Oileld Review 6, no. 2 (April 1994): 418.

2. Koch GH, Brongers MPH, Thompson NG, Virmani YP and Payer JH: Corrosion Costs and Preventive Strategies in the United States, Washington, DC: US Department of Transportation Federal Highway Administration, Ofce of Infrastructure Research and Development, Publication no. FHWA-RD-01-156, September 2001.

> Summary of corrosion problems and solutions. In the oil eld, corrosion is pervasive and takes many forms. By properly identifying the source of corrosive attack, an operator can implement a suitable corrosion monitoring and control program.

Problem Control MethodsCause of Corrosion Monitoring

Oxygen corrosion

Sulfate-reducingbacteria (SRB)

Hydrogen sulfide stress corrosion crackingHydrogen-inducedcracking

Acid corrosion

Galvanic (bimetallic) corrosion

Pitting corrosion (rapidcorrosion at defectsin inert surface film)

Subdepositcorrosion

Chloride corrosion(rapid cracking onexposure to hotchloride media)

Fatigue

Crevice corrosion

Hydrogen sulfide corrosion pitting

Carbon dioxidecorrosion

Water and oxygen sampling Iron counts Corrosion probes Oxygen sensors Coupon surveys Wall thickness surveys Visual internal inspections Visual surveys

Anaerobic bacteria counts Chlorine residuals measurements

Materials quality control

Acid inhibitor checks

Design reviews

Equipment inspections

Equipment inspections Bacteria counts

Equipment inspections Oxygen analyses

Equipment inspections

Equipment disassembly and inspections Leak detections

Probes Iron counts Wall thickness surveys

Probes Iron counts Wall thickness surveys

Resistant materials Oxygen scavengers Oxygen stripping Improved seal design Coatings Cathodic protection

Biocides Chlorination

Suitable materials

Acid inhibitors

Improved design

Electrical isolation of metals (cathodic coating)

Materials selection

Pigging Biocides Improved sealing and design Minimum velocity design

Materials selection

Vibration design

Improved design Materials selection

Control of contaminated gas

Degassing at low pressures

Use of resistant materials

Degassing at low pressures Control of contaminated gas Use of resistant materials

Oxygenated water Internal attack External attack

Anaerobic fluids Stagnant fluids Conditions under scales or other deposits

Produced fluids containing hydrogen sulfide Anaerobic systems contaminated with SRB

Stimulation and cleaning acids

Two metals with different ionic potentials in a corrosive medium

Immersion Inert surface films

Wet solids deposits Biofilms Porous gaskets

Salt solution Oxygen and heat

Rotating equipment Wave-, wind- or current-induced loading

Poor design Imperfections in metal

Water from production aquifer or other deep aquifer Water contaminated by stripping or lift gas

Water from production aquifer or other deep aquifer Water contaminated by stripping or lift gas

20 Oileld Review

acidic gaseswhich may present more-aggres-sive corrosion environments.

The industry has advanced several methods tocombat corrosion and extend the operating life ofa well. These may be broadly classied into fourmain categories: metallurgysubstituting traditional wellbore

tubulars with those manufactured with a corro-sion-resistant alloy (CRA)

chemicalmodifying production uids toreduce the intensity of corrosive attacks or cre-ating barriers that isolate the metal from pro-duced uids through the application of aprotective coating

injectionpumping surfactant-base uids thataggregate at the metal surface and block metal-water contact, thus inhibiting corrosion

cathodic protectionusing DC current to cre-ate impressed cathodic protection.3

The rst optionupgrading tubulars to thosecomposed of CRAmay be cost prohibitive on alarge scale. In the US alone, there are more than100,000 producing oil and gas wells with casing,tubing, wellheads, processing equipment andgathering lines.

Manufacturers may employ another mitiga-tion option: applying permanent coatings, whichcombat corrosion by forming a resistant barrierbetween the corrosive uid media and the metalsurface. Many coating types exist and are gener-ally categorized as follows: metalliczinc, chromium and aluminum inorganicenamels, glasses, ceramics and

glass-reinforced linings organicepoxies, acrylics and polyurethanes.4

As with CRAs, coatings may promise a longeroperating life with reduced maintenance, butthey come at a cost premium.5

Operators may use inhibition by chemicalmeans during the production stage of the well tomitigate corrosion on the internal surface of pip-ing and equipment. Corrosion inhibitors are typi-cally surfactant-base chemical formulations thatare added to the production stream in concentra-tions ranging from tens to several hundred partsper million (ppm). The inhibitor moleculesmigrate and collect at surfaces; in the case of awells production infrastructure, the moleculescollect at the metal surface to form a barrierbetween it and the corrosive uid phase. In thisway, they act in a manner similar to that of a coat-ing, but at a lower cost than that of a permanentcoating or a CRA. Unlike a coating, a corrosioninhibitor must be reapplied to replenish theinhibitor lm that is degraded or washed away bythe owing action of the production stream.6

Corrosion prevention through cathodic pro-tection works by forcing anodic areas of themetalthose susceptible to corrosive attackto become cathodic or noncorrosive. To accom-plish this, operators apply a DC current throughthe metal to counteract the corrosion currentatechnique known as impressed cathodic protec-tion (ICP)or use sacricial anodes, which arecomposed of metal that has a greater corrosiontendency than the metal to be protected.7

This article focuses on corrosion monitoringand measurement techniques for downhole infra-structure during production. Case studies from

the Middle East demonstrate how corrosion mon-itoring tools and mitigation technologies havehelped operators identify the location and sever-ity of corrosion in the subsurface infrastructure,which informed each companys choice of mitiga-tion solution.

Corrosion and the Life CycleCorrosion is a major concern throughout the lifeof a well, and specic considerations and mitiga-tion strategies are required at each stage. Assetpersonnel usually begin making corrosion miti-gation decisions for a well before drilling.During the well design stage, the operator con-ducts comprehensive reservoir studies, whichinclude reservoir simulation modeling, corestudies and uid analysis from offset well data.Engineers use the information obtained fromthese studies to develop risk assessments forcorrosion threats in subsequent stages of thewell. Engineers then develop and implementmitigation strategies that include appropriatematerials selection, optimal production rates,monitoring programs and corrosion inhibitortreatments (above).

During the drilling process, operators focuscorrosion mitigation strategies on extending theworking life of drillpipe, which is exposed to highoperational stresses as well as potentially corro-sive drilling muds and formation uids. The drill-pipe may undergo one of several types of corrosionmechanisms, including localized pitting, in whichH2S, chloride salts or oxygen in water-base drill-ing muds cause a corrosion rate that exceeds25 cm [9.8 in.] per year.8 Other corrosion sources

> Corrosion considerations at each stage of the asset life cycle. During each stage of a wells life, engineers must consideroperational factors to keep corrosion at bay and minimize the threat of production uid leaks into the surrounding environment.

Perform reservoir modeling.

Perform core analysis.

Perform materials selection.

Perform risk analysis.

WellDesign

WellDecline Decommissioning

Drilling andCompletions Production

Select suitable drilling mud.

Select suitable alloys for pipe work and equipment.

Select suitable oxygen and sulfide scavengers.

Ensure long-term containment of abandoned well.

Ensure compliance with environmental regulations.

Implement more-stringent and expansive asset integrity evaluation.

Implement or expand oil and water separation operations.

Use corrosion monitoring tools and services.

Use corrosion mitigation technologies (corrosion inhibitors, sand control systems and oxygen scavengers).

Evaluate infrastructure condition and track corrosion rates.

Implement repairs and replacement strategies as needed.

Prod

uctio

n

Autumn 2013 21

include the presence of CO2 at a partial pressureof 20 to 200 kPa [3 to 30 psi] or greater, microbio-logically inuenced corrosion (MIC) caused bythe presence of certain bacteria (microbes) inproduced uids and crevice corrosion in whichlocalized corrosion rates at metal-to-metal ormetal-to-nonmetal interfaces, such as at jointcouplings or gaskets, reach elevated levels andlead to pitting or cracking.9

The common ingredient in these various cor-rosion events is drilling mud. To prevent drillingmuds from becoming corrosive, mud engineersuse specic chemical treatments in the mud.These treatments focus on keeping the pH of themud within an acceptable rangetypicallybetween 9.5 and 12by dosing it with alkali oradding oxygen scavengers to reduce dissolved oxy-gen levels below 1 ppm or by adding sulde scav-engers that eliminate H2S from the mud system.10

The completion phase of a well refers to theassembly and installation of downhole tubularsand equipment such as packers and articial liftpump systems. Information collected during thewell planning stage, including the temperatureand pressure of the reservoir and the compositionof the production uids, helps inform the opera-tors decision on corrosion mitigation measures tobe included in the completion. For example,anticipation of H2S or CO2 production may leadthe operator to use CRAs in the completion casingstrings, control valves, permanent downholegauges and hydraulic and electric control lines.11

At the end of the wells life cycle, hydrocarbonproduction levels falloften with a correspond-ing rise in water production ratesto a point atwhich the well is no longer protable and theoperator must plug and abandon (P&A) it. Theoperators corrosion mitigation strategies shift topermanently prevent reservoir uid releases tothe environment long after the well is aban-doned. The basics of a P&A operation includeremoving completion hardware, setting isolationplugs and squeezing cement into the annularspaces at various depths to permanently seal offproducing and water-bearing zones.12

P&A operations represent a pure cost, whichmotivates operators to conduct these activities asquickly and efciently as possible. At the sametime, a P&A job must be carried out with strictadherence to government regulatory require-ments. While these regulations vary widely intheir severity and punitive measures, should aregulator nd a leak in a previously abandonedwell, it is the responsibility of the operator toreturn to make any necessary repairs and replugthe welloften at a signicantly higher costthan that of the original P&A operation.

Operators realize a prot during a wells pro-duction stage, which may last from only a fewyears to several decades. During this stage, cor-rosion mitigation efforts are generally focusedon keeping corrosion rates low and preventingleaks (below). The operator must continually

monitor and inspect the infrastructure to gaugethe integrity of downhole and surface pipingand equipment and the effectiveness of themitigation.

Companies use a variety of corrosion monitor-ing techniques in oil and gas elds. Techniques are

3. Nalli K: Corrosion and Its Mitigation in the Oil & GasIndustryAn Overview, PetroMin Pipeliner (JanuaryMarch 2010): 1016.

4. Heim G and Schwenk W: Coatings for CorrosionProtection, in von Baekman W, Shwenk W and Prinz W(eds): Handbook of Cathodic Corrosion Protection, 3rd ed.Houston: Gulf Coast Publishing Company (1997): 153178.

5. Craig BD, Lane RA and Rose DH: Corrosion Preventionand Control: A Program Management Guide for SelectingMaterials, Spiral 2, 2nd ed. Rome, New York, USA:Advanced Materials, Manufacturing, and TestingInformation Analysis Center, Alion Science & Technology(September 2006): 40.

6. Corrosion inhibitors are applied either continuously bystrategically injecting them into the well or productionstring at a steady rate to maintain a desiredconcentration or through batch application, wherein alarger volume often called a batch, or slug, of inhibitor isapplied into the well on a periodic basis. Continuousinjection provides an added benet in that the inhibitorcan be applied without shutting in the well.

7. For more on impressed cathodic protection: Brondel et al,reference 1.

> Corrosions impact on casing integrity. Casing leaks typically arise fromexcessive corrosion in the production system. These leaks, which can provecostly and environmentally damaging, may allow additional formation waterand sand to enter the production string of the well (blue arrow). Alternatively,crossows (green arrows) may result, which can be difcult to characterizeand treat, and in severe cases, the operator may have to pull and replace theentire casing string.

Water sand

Oil sand

Perforations

Packer

Cement sheath

Corrosion-inducedcracks

8. The corrosion rate is the thickness of metal that wouldbe lost to corrosion in one year. This rate clearlyindicates that a hole would be created in drillpipe wall infar less than a year.

9. For more on microbiologically inuenced corrosion:Augustinovic Z, Birketveit O, Clements K, Freeman M,Gopi S, Ishoey T, Jackson G, Kubala G, Larsen J,Marcotte BWG, Scheie J, Skovhus TL and Sunde E:MicrobesOileld Enemies or Allies?,Oileld Review 24, no. 2 (Summer 2012): 417.

10. Sloat B and Weibel J: How Oxygen CorrosionAffects Drill Pipe, Oil and Gas Journal 68, no. 24(June 1970): 7779.

11. Saldanha S: Intelligent Wells Offer Completion Solutionfor Lower Tertiary Fields, Offshore Magazine 72, no. 8(August 1, 2012): 5457.

12. For more on plug and abandonment operations:Abshire LW, Desai P, Mueller D, Paulsen WB,Robertson RDB and Solheim T: Offshore PermanentWell Abandonment, Oileld Review 24, no. 1(Spring 2012): 4250.

22 Oileld Review

selected based in part on the systems ease of implementation for a given application or location in the production system, the ease with which results can be interpreted and the relative severity of corrosive attack. Some corrosion measurement techniques use inline monitoring tools placed directly in the production system; these tools are exposed to the owing production stream. Other techniques provide analysis of corrosion effects after the fact in a laboratory setting.13

The weight loss technique using coupons, a direct visual identication method, is a well-known and simple monitoring method. This tech-nique exposes a specimen of materialthe couponto the process environment for a given period of time before a technician removes it from the system and analyzes it for its physical condition and the amount of weight lost.14 The

coupon technique is advantageous because cou-pons can be fabricated from the same alloy that makes up the system under study, the corrosion rate can be easily calculated from the coupons weight loss over the time of exposure and the technique allows visual verication of corrosion deposits or localized corrosion. However, if a cor-rosion event such as a leak occurred while the coupon was in the system, the operator could not use the coupon alone to accurately pinpoint its time of occurrence. In addition, the coupon tech-nique is applicable only in system locations that provide easy or practical access for placing and extracting the coupon.

This second limitation makes coupon moni-toring, or any visual inspection technique, essen-tially impossible for the wells downhole tubulars and casing strings. The remaining options are indirect measurement techniques that incorpo-

rate one or more of the various logging tools that are deployed downhole via wireline, tractor or coiled tubing.

Advances in Downhole Corrosion MonitoringLogging techniques for monitoring downhole cor-rosion include ultrasonic, electromagnetic and mechanical methods that yield detailed informa-tion about the location and extent of a corrosion event. Ultrasonic monitoring employs a central-ized sonde that is immersed in well uid and uses a subassembly containing a rotating transducer to perform measurements.15 Most ultrasonic tools work by the principle of pulse echo measure-ment, and operators choose a transducer with the characteristics necessary for the type of mea-surement to be taken. Measurements include cement evaluation, openhole imaging and corro-sion imaging.

A USI ultrasonic imager transducer, which transmits an ultrasonic signal at a frequency ranging from 200 to 700 kHz to make the casing resonate, is typically designed for cement evalua-tion and pipe inspection. The quality of the cement bond is directly related to the degree of casing resonance: A good cement bond dampens the acoustic signal and causes a low-amplitude secondary signal to be returned to the trans-ducer; a poor cement job or free pipe allows the casing to ring and returns a higher amplitude echo. Additionally, USI measurements include 2D internal radius imaging of the casingderived from the traveltime of the main echo from the internal surfaceand the 2D casing thickness, derived from the frequency response.

Higher resolution casing measurements may be acquired with the UCI ultrasonic casing imager, which uses a focused 2-MHz transducer with improved resolution compared with that of the USI tool (left).16 The UCI tool records two echoes: the main echo from the internal surface of the casing and the smaller echo from the external surface. The radius and thickness of the casing are com-puted from the arrival times of the two echoes. The relative sizes, or amplitudes, of the two echoes are qualitative indicators of the casing condition. Although the UCI device provides a better indica-tion of the condition of the casing than does the USI imager, use of the UCI tool is limited to opera-tions in which the well uid comprises brines, oil and light oilbase or water-base muds. Weighted muds produce an acoustic attenuation that is too strong to allow meaningful measurement.

Ultrasonic inspection provides several advan-tages as a corrosion measurement tool, including its sensitivity to both internal and external

> Basic principles of the UCI ultrasonic corrosion imager. The UCI tool uses a 2-MHz focused transducer to improve the resolution of the ultrasonic measurement. The transducer also acts as a receiver of the reected signal and records its amplitude and time of arrival. This signal is emitted (or pulsed) through the well uid and into the casing (top). As this signal encounters a discontinuity, such as the inner or outer wall of the casing (center), the signal is reected back. Most of the energy is reected in the initial echo at the inner casing wall because of the large impedance contrast between the mud and the steel; the remaining energy transmitted into the casing is again reected at the outer wall. The signal reected back at the inner wall can be used to evaluate the casing condition and radius. The time difference between the rst two echoes can be used to determine the thickness of the casing (bottom). In comparison, the USI tool is more commonly used for ultrasonic pipe inspection and employs a 200- to 700-kHz unfocused ultrasonic transducer to induce a casing resonance. In the USI measurement, thickness is determined from the resonance frequency. (Adapted from Hayman et al, reference 15.)

Amplitude

Ampl

itude

Transducer Ultrasonic signal

Casing

Radius Thickness

Time

Autumn 2013 23

RZ

RZ

TZ

RLSRLL

TL

RLS

RLL

THRP

Discriminatortransmitter, TH

Tool outerdiameter

PipePadreceiver, RP

2D thickness

2D discrimination

TL

RP RP

TH

RP

Skin depth decay

Average thickness

RLS

RLL

RLL

RLS

TL

d

Z properties

RZ

RZ

TZ

=ID0

1 1

defects and instantaneous in-eld noticationwhen a defect is encountered. In addition, thetechnique requires access to only one side of thematerial to gauge the condition of the entireobject and obtain detailed exterior and interiorimages of the object. However, inspection is dif-cult for materials that are heterogeneous in com-position, irregular in shape or thin; to improvethe results of the inspection, technicians mustprepare the internal surface prior to measure-ment by scraping away scale or other debris.

Operators may also employ another corro-sion monitoring method: electromagnetic (EM)-based inspection. The basic principle of thistechnique involves measuring the changes to amagnetic eld as it passes through a metalobject; the changes are related to the conditionof the material such as its thickness and itselectromagnetic properties.

The industry currently uses two EM corro-sion monitoring tools. The rst, a ux leakagetool, magnetizes the metal object using an elec-tromagnet. When the magnetic ux encountersa damaged section or hole in the material, partof the ux leaks out of the metal; coils on thetools senso