4

Corrosion in the Oil Industry

Most metals exist in nature as stable ores of oxides, carbonates or sulfides. Refining them, to make them

useful, requires energy. Corrosion is simply nature’s way of reversing an unnatural process back to a lower

energy state. Preventing corrosion is vital in every step in the production of oil and gas.

Denis BrondelMontrouge, France

Randy EdwardsColumbus, Ohio, USA

Andrew HaymanClamart, France

Donald HillTulsa, Oklahoma, USA

Shreekant MehtaSt. Austell, England

Tony SemeradMobilSumatra, Indonesia

For help in preparation of this article, thanks to DylanDavies, Schlumberger Cambridge Research, AhmadMadjidi, Schlumberger GeoQuest, Abu Dhabi, UAE;Nabil Mazzawi, Schlumberger Wireline & Testing,Tripoli, Libya; Perry Nice, Statoil, Stavanger, Norway;Barry Nicholson, Schlumberger Wireline & Testing,Jakarta, Indonesia; Daniel Roche, Elf, Bergen, Norway;Philippe Rutman and Derek Stark, Schlumberger Wire-line & Testing, Montrouge, France; Dave Thompson,Schlumberger Wireline & Testing, Bergen, Norway; andPiers Temple, Joe Vinet and Mohamed Watfa, Schlum-berger Wireline & Testing, Abu Dhabi, UAE.CET (Cement Evaluation Tool), CORBAN, CPET (Corro-sion and Protection Evaluation Tool), FACT (Flux ArrayCorrosion Tool), IDCIDE, IDFILM, IDSCAV, METT (Mul-tifrequency Electromagnetic Thickness Tool), PAL (PipeAnalysis Log), UBI (Ultrasonic Borehole Imager) andUSI (UltraSonic Imager) are marks of Schlumberger.

Corrosion costs US industries alone an esti-mated $170 billion a year. The oil industry,with its complex and demanding produc-tion techniques, and the environmentalthreat should components fail, takes anabove average share of these costs.1

Corrosion—the deterioration of a metal orits properties—attacks every component atevery stage in the life of every oil and gasfield. From casing strings to production plat-forms, from drilling through to abandon-ment, corrosion is an adversary worthy ofall the high technology and research we canthrow at it.

Oxygen, which plays such an importantrole in corrosion, is not normally present inproducing formations. It is only at thedrilling stage that oxygen-contaminated flu-ids are first introduced. Drilling muds, leftuntreated, will corrode not only well casing,but also drilling equipment, pipelines andmud handling equipment. Water and car-bon dioxide—produced or injected for sec-ondary recovery—can cause severe corro-sion of completion strings. Acid—used toreduce formation damage around the wellor to remove scale—readily attacks metal.Completions and surface pipelines can beeroded away by high production velocities

or blasted by formation sand. Hydrogen sul-fide [H2S] poses other problems (next page).Handling all these corrosion situations, withthe added complications of high tempera-tures, pressures and stresses involved indrilling or production, requires the expertiseof a corrosion engineer, an increasingly keyfigure in the industry.

Because it is almost impossible to preventcorrosion, it is becoming more apparent thatcontrolling the corrosion rate may be themost economical solution. Corrosion engi-neers are therefore increasingly involved inestimating the cost of their solutions to cor-rosion prevention and estimating the usefullife of equipment. For example, develop-ment wells in Mobil’s Arun gas field inIndonesia have been monitored for corro-sion since they were drilled in 1977.

Production wells were completed using7-in. L-80 grade carbon steel tubing—anH2S-resistant steel—allowing flow rates inexcess of 50 MMscf/D [1.4 MMscm/D] atover 300°F [150°C]. High flow rates, H2Sand carbon dioxide [CO2] all contributedto the corrosion of the tubing. Laboratoryexperiments simulated the Arun well con-ditions, alongside continued field monitor-ing. These help find the most economicalsolution to the corrosion problem.2 Theresults showed that the carbon steel tubingwould have to be changed to more expen-sive chromium steel or to corrosion-resis-tant alloy (CRA).

Oilfield Review

2. Sutanto H, Semerad VAW and Bordelon TP: “Simula-tion of Future Wellbore Corrosion With Low Produc-tion Rate Field Tests,” paper 571, presented at the Cor-rosion 91 NACE Annual Conference and CorrosionShow, Cincinnati, Ohio, USA, March 11-15, 1991.Semerad VAW and Sutanto H: ”Wellbore CorrosionLogging of Deep Hot Corrosive Wells,” paper OSEA90141, presented at the 8th Offshore South East AsiaConference, Singapore, December 4-7, 1990.Asphahani AI, Prouheze JC and Petersen GJ: “Corro-sion-Resistant Alloys for Hot, Deep, Sour Wells: Prop-erties and Experience,” SPE Production Engineering 6,

nCorrosion in everyaspect of the oilindustry. From gen-eralized corrosioncaused by oxygen-rich environmentson marine struc-tures to sulfidestress corrosion inhostile wells, thecorrosion engineeris faced with awhole gamut ofproblems.

1. For a comprehensive reference book see:ASM Handbook Volume 13 Corrosion. Materials Park,Ohio, USA: ASM International, 1992.For an easier read:Jones LW: Corrosion and Water Technology forPetroleum Producers. Tulsa, Oklahoma, USA: OGCIPublications, 1988.Tuttle RN: “Corrosion in Oil and Gas Production,”Journal of Petroleum Technology 39 (July 1987): 756-762.

Paint Cathodic protection

Stress

Stress

Oxygen-rich seawater

Meteoric oxygen-rich water

CO2, H2S, water, bacteria

Crustaceans

Cement

Mud inhibitors, scavengers

Water injection, oxygen scavengers

Acidizing

Pipeline coating

Sacrificialanodes

Inhibitors

Unsupportedcasing stress

Scale

The Basic Corrosion CellBy recognizing corrosion when it doesoccur, and by understanding the mecha-nisms involved, corrosion engineers maybegin to eliminate corrosion by design.

The basic galvanic corrosion mechanismfollows the principle of a battery. A typicalbattery requires two dissimilar metals con-nected together and immersed in an elec-

no. 4 (November 1991): 459-464.Farooqul MASZ and Holland S: “Corrosion-ResistantTubulars for Prolonging GWI Well Life,” paper SPE21365, presented at the SPE Middle East Oil Show,Manama, Bahrain, November 16-19, 1991.

5April 1994

Steel

FeSx

Fe2O3.H2Ox

Fe2CO3

O2

H2S

CO2

O2

H2S or CO2 H2

H2O

1/2 O2

2 OH–

e–

e–

Fe

Cathode

Anode

Electrolyte

e– H+

H+

Fe++

e– e–

e–

nCorrosion on a steel surface. At anodicsites, iron readily goes into solution as ironions, Fe++, which combine with oxygen,O2, hydrogen sulfide, H2S, or carbon diox-ide, CO2, depending on the constituents ofthe electrolytic fluid. These form corrosionproducts or scales as rust—iron oxide[Fe2O3•H2 Ox], iron sulfides [FeSx] or ironcarbonate [Fe2CO3]. While this is happen-ing, the electrons migrate to the cathode.At the cathode surface, they reduce oxy-genated water to produce hydroxyl ions[OH-] or reduce hydrogen ions to producehydrogen gas [H2].

trolyte (below).3 All metals have a tendencyto dissolve or corrode to a greater or lesserdegree. In this case, the metal with thegreater tendency to corrode forms the nega-tive pole and is called the anode.4 Whenthe two are connected, the other metalforms the positive pole, or cathode.

Loss of positive metal ions from the anodecauses a release of free electrons. This pro-cess is called oxidation. The buildup ofelectrons generates an electrical potential,causing them to flow through the conductorto the cathode. At the cathode, excess elec-trons are neutralized or taken up by ions inthe electrolyte. This process is called reduc-tion. As long as reduction reactions predom-inate, no metal is lost at the cathode. Theanode will continue to corrode as long asthe electric circuit is maintained and themetal ions are removed from solution bycombining with other elements to make upcorrosion products.

Anodes and cathodes can form on a sin-gle piece of metal made up of small crystalsof slightly different compositions. (They canbe next to each other or separated by largedistances–sometimes tens of kilometers.)The electrolyte may simply be water (right).For example, pure iron [Fe] in steel has a

6

nCorrosion cell. The basic corrosion cell isformed by two dissimilar metals immersedin an electrolyte joined by a conductor.One electrode will tend to corrode morereadily than the other and is called theanode. The anode loses positive metal ionsto the electrolyte leaving free electrons anda net negative charge. At the other elec-trode, called the cathode, free electrons aretaken up by ions in the electrolyte leavinga net positive charge. Free electrons cantravel from anode to cathode along theconductor. The electrolyte then completesthe circuit.

Conductor

e–

Anode Cathode

Metal ions (M+) Electrolyte

tendency to dissolve, going into solution asFe++. As each Fe++ ion is formed, two elec-trons are left behind, giving that area of themetal a small negative charge. If nothinghappens to remove Fe++ ions around theanodic site, the tendency to dissolve willdiminish. In oil production, Fe++ ions areremoved by reacting with oxygen [O2],hydrogen sulfide, or carbon dioxide. Thecorrosion products are precipitates or scalesof rust [Fe2O3], iron sulfides [FeSx] or ironcarbonate [Fe2CO3].

Excess electrons flow away from theanodic region to a site where they form acathode, and where reduction occurs.Reduction of oxygenated water formshydroxyl ions [OH

_]. If oxygen is not pre-

sent, but CO2 or H2S is, then the dominantcathodic reaction is the reduction ofhydrogen ions to produce hydrogen gas. Ifthe electrolyte is salt water, chlorine gas isproduced (see “Corrosion Mechanisms,”page 8).

Identifying the Causes and Applying ControlsThere are many sources of corrosion andmany more methods of slowing the processdown. This section looks at different partsof the industry and identifies typical corro-sion problems and some of the solutions(next page).

Offshore structures—On surface equip-ment, the simplest solution is to place aninsulating barrier over the metal concerned.Offshore installations are often painted withzinc-rich primers to form a barrier againstrain, condensation, sea mist and spray. Thezinc primer not only forms a physical bar-rier, but also acts as a sacrificial anodeshould the barrier be breached.

Offshore structures are also protected inother ways.5 The zone above the high tidemark, called the splash zone, is constantlyin and out of water. The most severe corro-sion occurs here. Any protective coating orfilm is continually eroded by waves andthere is an ample supply of oxygen andwater. Common methods of controlling cor-rosion in this zone include further coatingand also increasing metal thickness to com-pensate for higher metal loss.

The part of the structure in the tidal zone issubjected to less severe corrosion than thesplash zone and can benefit from cathodicprotection systems at high tide.6 Cathodicprotection works by forcing anodic areas tobecome cathodes. To achieve this, a reversecurrent is applied to counteract the corrosioncurrent. The current can be generated by anexternal DC source—impressed cathodicprotection—or by using sacrificial anodes.

The rest of the structure—exposed to lesssevere seawater corrosion—is protected bycathodic protection. However, crustaceansand seaweed attach to the submerged partsadding weight that may increase stress-related corrosion. This mechanism occurswhen the combined effects of crevice, orpitting, corrosion and stress propagatecracks leading to structural failure. How-ever, a covering of life does restrict oxygenreaching metal, and so reduces corrosion.

Other forms of structural stress are alsoimportant. Low-frequency cyclic stress—resulting from factors such as waves, tidesand operating loads—can allow time forcorrosion within cracks as they are opened.Modeling and accounting for these stressesare therefore an extremely important part ofcorrosion prevention.7

Oilfield Review

Platform

Superstructure

Mean high tide

Mean low tide

Mud line

Piling

Ultraviolet exposure

Precipitated salt

Condensation

Atmospheric sea exposure (pollutants, dust and sand)

Maximum corrosion (wet and plentiful oxygen supply)Severe corrosion (continuous wetting and drying)

Maximum pitting corrosion (tidal area, sand and mud scouring)

General seawater corrosion(fouling organisms, chemical and biological pollutants)

Little corrosion(shifting bottom)

0 2 4 6

Relative corrosion rate

5. Watts RK: “Designing for Corrosion Control in SurfaceProduction Facilities,” paper SPE 9985, presented at theSPE International Petroleum Exhibition and TechnicalSymposium, Beijing, China, March 18-26, 1982.Schremp FW: “Corrosion Prevention for Offshore Plat-forms,” paper SPE 9986, presented at the SPE Interna-tional Petroleum Exhibition and Technical Symposium,Beijing, China, March 18-26, 1982.

6. ASM Handbook, reference 1: 1254-1255.Jones, reference 1: 75-78.

7. Barreau G, Booth G, Magne E, Morvan P, Mudge P,Pisarki H, Tran D, Tranter P and Williford F: “NewLease on Life for the 704,” Oilfield Review 5, no. 2/3(April/July 1993): 4-14.

8. Maxwell S: “Assessment of Sulfide Corrosion Risks in Offshore Systems by Biological Monitoring,” SPE Production Engineering 1, no. 5 (September 1986): 363-368.

3. A corrosion cell may also be formed by having thesame metal in two different electrolytes.An electrolyte is a nonmetallic electric conductor.Current is carried through an electrolyte by themovement of charged atoms called ions. Negativeions have extra electrons and positive ions have lostelectrons.

4. Confusion often arises over whether an anode ispositive or negative, because in a driven cell, suchas electroplating baths or vacuum tubes in oldradios, the positive is the anode and the negative thecathode. In any battery, however, including a corro-sion cell, the cathode has positive charge and theanode negative charge. At the anode, ferrous ions[Fe++] leaving the surface leave a net negativecharge, and the electrons flow through the metal tothe cathode. At the cathode, hydrogen ions [H+] discharge themselves to leave a positive charge and

nDiverse corrosiveenvironmentsattacking an off-shore rig (above,left). Sacrificialanodes on the legand spud tank ofSedco Forex’s Tri-dent IV jackup rig(left). Cathodic pro-tection is a com-mon way of com-bating corrosion;sacrificial anodesprovide onemethod.

The bottom of a jackup rig or productionplatform sinks into the seabed and isattacked by H2S produced by sulfate-reduc-ing bacteria (SRB).8 However, cathodic pro-tection also shields this part of the structureand, because of reduced oxygen supply, theprotection current required tends to be lessthan for the rest of the rig.

Drillpipe corrosion—While a well is beingdrilled, stress is applied not only to the rigstructure, but also to the drilling equipment.Drillpipe is probably the most harshlytreated of all equipment. It is exposed to for-mation fluids and drilling mud, subjected tostress corrosion and erosion by cuttings.Joints of drillpipe are made from hardenedhigh-strength steel and are likely to sufferfrom fatigue failures started by deep corro-sion pits caused by oxygen, either from themud itself or from being stacked wet.Drillpipe is sometimes coated internally,with baked resins or fusion bonded epoxies,to counteract corrosion. Once this coatinghas disappeared, however, corrosion can berapid. A common area where drillpipe leaksor washouts occur is in the threadeddrillpipe connections called tool joints. The

(continued on page 11)

result in free hydrogen—polarization.

7April 1994

Electrochemical Corrosion

Galvanic Corrosion (Two Metal)—Two dissimilar

metals in a conductive medium develop a poten-

tial difference between them. One becomes

anodic, the other cathodic. The anode loses metal

ions to balance electron flow. Because metals are

made up of crystals, many such cells are set up,

causing intergranular corrosion. Problems are

most acute when the ratio of the cathode-to-

anode area is large.

Crevice Corrosion—Much metal loss in oilfield

casings is caused by crevice corrosion. This

localized form of corrosion is found almost exclu-

sively in oxygen-containing systems and is most

intense when chloride is present. In the crevice,

metal is in contact with an electrolyte, but does

not have ready access to oxygen.

At the start of the reaction, metal goes into

solution at anodic sites and oxygen is reduced to

hydroxyl ions at cathodic sites. Corrosion is ini-

tially uniform over the entire area including the

crevice. As corrosion continues in the crevice,

oxygen becomes depleted and cathodic oxygen

reduction stops. Metal ions continue to dissolve

at anodes within the crevice, producing an excess

of positive charges in solution. Negatively

charged chloride (or other anions) now migrate to

the developing anodes to maintain electroneu-

trality. They act as a catalyst, accelerating corro-

sion. At this point, crevice corrosion is fully

established and the anodic reaction continues

with ferrous ions [Fe++] going readily into solu-

tion (right).

Pitting corrosion is another form of crevice cor-

rosion where a small scratch, defect or impurity

can start the corrosion process. Again, a buildup

of positive charges occurs in a small pit on the

metal surface. Chlorine ions from a saline solu-

tion migrate towards the pit. These, coupled with

the formation of hydrogen ions, act as a catalyst

causing more metal dissolution.

Stray-Current Corrosion—Extraneous AC and

DC currents in the earth arriving at a conductor

will turn the point of arrival into a cathode

(above). The place where the current departs will

become anodic, resulting in corrosion at that

point. A DC current is 100 times more destructive

than an equivalent AC current. Only 1 amp per

year of stray DC current can corrode up to 20 lbm

[9 kg] of steel. Cathodic protection systems are

the most likely sources of stray DC currents in

production systems.

Surface installation Corrosion

Cathodic protection

Corrosion

Corrosion

O2

M+

CI–

OH–

Na+

M+ O2

OH–O2

OH–

CI–

Na+

Na+

CI–

O2

e– e–

e–

e–

M+

M+

nStray-current corrosion. Current paths are shown between surface installation, electrical machinery,pipelines and a well. Current leaving the casing sets up an anodic area and corrosion.

Corrosion Mechanisms

Corrosion encountered in petroleum production operations involves several mechanisms. These have been grouped into

electrochemical corrosion, chemical corrosion and mechanical and mechanical/corrosive effects.

nCrevice corrosion. This type of corrosion oftenstarts at drillpipe joints, tubing collars or casing col-lars. The gap in the joint becomes devoid of oxygenand anodic. In salty water the corrosion is promotedby the migration of negatively charged chlorine ions[Cl-] to the crevice. These not only counteract thebuildup of positive charges around the crevice, butalso act as a catalyst accelerating the dissolution ofmetal [M+]. This ongoing process leads to a deep pit.

8 Oilfield Review

nBarnacle-type corrosion. As tubing corrodes in ahydrogen sulfide and water environment, iron sulfidescale builds up. This is porous and is also cathodicwith respect to the steel tubing. An intervening layerof iron chloride [FeCl2] is acidic and prevents precip-itation of FeS directly onto the steel surface. Thisestablishes a pit-forming corrosion cell.

Chemical Corrosion

Hydrogen Sulfide, Polysulfides andSulfur—Hydrogen sulfide [H2S] when dissolved

in water, is a weak acid and, therefore, it is a

source of hydrogen ions and is corrosive. (The

effects are greater in deep wells, because the pH

is further reduced by pressure.) The corrosion

products are iron sulfides [FeSx] and hydrogen.

Iron sulfide forms a scale that at low tempera-

tures can act as a barrier to slow corrosion. The

absence of chloride salts strongly promotes this

condition and the absence of oxygen is abso-

lutely essential. At higher temperatures the scale

is cathodic in relation to the casing and galvanic

corrosion starts. In the presence of chloride ions

and temperatures over 300°F [150°C] barnacle-

type corrosion occurs, which can be sustained

under thick but porous iron sulfide deposits

(above, right). The chloride forms a layer of iron

chloride [FeCl2], which is acidic and prevents the

formation of an FeS layer directly on the corrod-

ing steel, enabling the anodic reaction to con-

tinue. Hydrogen produced in the reaction may

lead to hydrogen embrittlement.

Carbon Dioxide—Like H2S, carbon dioxide

[CO2] is a weakly acidic gas and becomes corro-

sive when dissolved in water. However, CO2 must

hydrate to carbonic acid [H2 CO3]—a relatively

slow process—before it becomes acidic. The cor-

rosion product is iron carbonate (siderite) scale.

This can be protective under certain conditions.

Siderite itself can be soluble. Conditions favoring

the formation of a protective scale are elevated

temperatures, increased pH as occurs in bicar-

bonate-bearing waters and lack of turbulence, so

that the scale film is left in place. Turbulence is

often the critical factor in the production or reten-

tion of a protective iron carbonate film. Siderite is

not conductive, so galvanic corrosion cannot

occur. Thus corrosion occurs where the protective

siderite film is not present and is fairly uniform

over the exposed metal. Crevice and pitting cor-

rosion occur when carbonic acid is formed. Car-

bon dioxide can also cause embrittlement, result-

ing in stress corrosion cracking.

Strong Acids (direct chemical attack)—Strong

acids are often pumped into the wells to stimu-

late production by increasing formation perme-

ability in the near wellbore region. For limestone

formations, 5 to 28% hydrochloric [HCl] acid is

commonly used. For sandstones, additions of

hydrofluoric acid—normally up to 3%—are nec-

Tubing

Pit

Chloride film

Well fluids

Methane, hydrogen sulfide, water

Iron sulfide scale

9April 1994

essary. In deep sour wells where HCl inhibitors

lose effectiveness, 9% formic acid has been

used. Corrosion control is normally achieved by

a combination of inhibitor loading and limiting

exposure time, which may range from 2 to 24 hr.

If corrosion-resistant alloys are present

(austenitic and duplex stainless steels), concern

for stress-corrosion cracking (SCC) and inhibitor

effectiveness may rule out the use of HCl. In

addition to spent acid, other stagnant columns

such as drilling and completion fluid, may also

be corrosive.

Concentrated Brines—Dense halide brines of the

cations of calcium, zinc, and, more rarely, mag-

nesium are sometimes used to balance forma-

tion pressures during various production opera-

tions. All may be corrosive because of dissolved

oxygen or entrained air. In addition, these brines

may be corrosive because of acidity generated

by the hydrolysis of metallic ions. Corrosion due

to acidity is more severe with dense zinc brines.

More expensive brines of calcium bromide are

now often used at densities above 14 lbm/gal

[1.7 gm/cm3] to avoid long-term exposure to zinc

chloride [ZnCl2] brines.

Biological Effects—The most important biological

effect is the generation of H2S by sulfate-reducing

bacteria. These anaerobic bacteria metabolize

sulfate ions (using an organic carbon source) and

produce hydrogen sulfide. They can thus intro-

duce H2S into an H2S-free system. Colonies of

SRBs can also form deposits that lead to crevice

corrosion with produced H2S accelerating corro-

sion, because it is known to be an anodic stimu-

lant. In low-flow rate systems, hard rust nodules

or tubercles can form creating differential oxygen

cells, which lead to crevice corrosion (below).

Erosion Corrosion—When erosion removes the

protective film of corrosion products, corrosion

can occur at a faster rate. Erosion corrosion may

play a role in CO2 corrosion. Under mild flow

conditions, sand may also cause erosion corro-

sion. This type of corrosion is also seen in anchor

chains where corrosion between links pro-

ceeds quickly.

Corrosion Fatigue—This results from subjecting

a metal to alternating stresses in a corrosive

environment. At the points of greatest stress,

the corrosion product film becomes damaged

allowing localized corrosion to take place.

Eventually this leads to crack initiation and crack

growth by a combination of mechanical and cor-

rosive action. Because of this combined action,

corrosion fatigue is greater at low stress cycles

that allow time for the corrosion process.

Welded connections on drillships, drilling and

production rigs and platforms are subject to this

type of corrosion.

Sulfide Stress Corrosion—Production of hydrogen

results from sulfide stress cracking (SSC). SSC

occurs when a susceptible metal is under tensile

stress and exposed to water containing hydrogen

sulfide or other sulfur compounds—generally

under anaerobic conditions. Corrosion cells gen-

erate FeS and atomic hydrogen. The amount of

metal loss is small and the FeS layer thin. The

layer of FeS promotes the movement of hydrogen

into the metal, usually into impurities at the grain

boundaries. Penetration of hydrogen into the body

of the metal reduces ductility. Accumulations of

hydrogen at imperfections generate tremendous

pressure. For hard high-strength steel the combi-

nation of lack of ductility and internal stress

superimposed on the tensile stress causes the

metal to break and crack (right). Penetration of

molecular hydrogen can also lead to blistering.

Chloride Stress Cracking (CSC)—While under

tensile stress, austenitic stainless steels can fail

by cracking when exposed to saline water above

200°F [95°C].

Stress Corrosion Cracking (combined with SSC,CSC and corrosion fatigue)—CSC is an example

of a broad range of stress-corrosion cracking,

defined as corrosion accelerated by tensile

stress. This type of corrosion starts at a pit or

notch, with cracks progressing into the metal pri-

marily along grain boundaries.

nHydrogen embrittlement and stress corrosion. When H2S is present, corrosion cells generate FeS andatomic hydrogen. The layer of FeS promotes the move-ment of hydrogen into the metal (top), and accumula-tions generate tremendous pressure. This leads toembrittlement and, if combined with static or cyclicstress, can lead to failure of the metal by corrosionfatigue or stress corrosion (middle). Stress corrosioncracking (bottom) starts at a pit or crevice. The zonearound the tip of the crevice becomes plastic understress allowing a crack to develop. Chlorine ions,which act as a catalyst to corrosion, can migrate intothe crack accelerating the process. The development ofthe crack within the plastic zone is another site forhydrogen embrittlement.

10 Oilfield Review

Mechanical and Mechanical/Corrosive Effects

Cavitation—This type of metal loss—often grain

by grain—is due to high-pressure shock waves,

generated from the collapse of minute bubbles

in high-velocity fluids impinging on nearby metal

surfaces. Cavitation metal loss is usually found

on pump impellers developing too low a suction

pressure.

Erosion—This is direct metal removal by the cut-

ting action of high-velocity abrasive particles.

Erosion failures (washouts) are seen in drillpipe

when leaks (loose connections or a corrosion

fatigue crack) allow drilling mud to flow through

the wall under high pressure. Erosion of flow-

lines at bends and joints by produced sand is

probably the other most common occurrence of

metal erosion in the petroleum industry.

nRust tubercle. Tuberculation is a complex localizedprocess that forms a nodule-like structure. It oftenforms in a region of low fluid velocity where adeposit of sludge or rust can shield a part of themetal and reduce the oxygen available to that area.The portion of steel exposed to water with low oxy-gen concentration becomes anodic and corrodes ata faster rate than the rest.

O2

OH

Iron or steel

O2

Highly anodic

Cathodic

Fe2

FeS

H2SSO2

SRB

Fe3

Hard rust tubercle

FeCO3

Fe(OH)3

4

Stress Corrosion Cracking

Plastic zone

Steel

Cl–HH

H+ H+Electrolyte

H2 H H

H2H H

H2

H

AirH H

Hydrogen Embrittlement

Corrosion fatigue

Hydrogen embrittlement

Stress corrosion

Static stress

Cyclic stress

Sulfide Stress Corrosion

Cl–Cl–

Cl–

Steel

threads provide ideal places for crevice cor-rosion, which can also occur in scars left onthe tool joints by makeup tongs. A specialgrease, commonly known as dope, lubricatesthe threads and helps prevent corrosion.9

Mud corrosion—Drilling mud also plays akey role in corrosion prevention. In additionto its well-known functions, mud must alsoremain noncorrosive. A greater awarenessof corrosion problems has come about bythe lower pH of polymer muds. Low pHmeans more acidic and hence more corro-sive. Oil-base muds are usually noncorro-sive and, before the introduction of polymermuds, water-base muds were used with rel-atively high pH of 10 or greater. So whenpolymer muds were introduced, corrosionfrom mud became more apparent.

Dissolved gases are the primary cause ofcorrosion in drilling fluids. The most com-mon are oxygen, carbon dioxide and hydro-gen sulfide. Oxygen, even in concentrationsas low as 1 part per million (ppm), is capa-ble of causing serious damage (top).

Oxygen can enter the mud system atmany points, especially at the surface mix-ing and storage tanks, and at the shakerscreens. Other entry points are at the cen-trifugal pumps, desanders and desilters. As aresult, the mud is usually oxygen-saturatedbefore it reaches the mud pumps. Sodiumsulfite- or ammonium bisulfite-based oxy-gen scavengers, such as Dowell’s IDSCAV,are routinely used in mud systems. Thesechemicals bond with oxygen in the mud toreduce its corrosivity.

Maintaining high pH is important in con-trolling corrosion rates by neutralizing acidscaused by H2S or CO2. Hydrogen sulfidecan enter the mud system directly from theformation or from thermally degraded mudproducts, SRBs or makeup water (above,right). Scavengers, such as sodium chro-mate, zinc chromate, and sodium nitrite,can quickly remove H2S. Dowell’s film-forming inhibitors IDFILM, help protect thedrillstring and casing. Triazine compoundsare used in products such as Dowell’sIDCIDE as biocides to control bacteria.10

Hydrogen sulfide will induce sulfide stresscracking (see “Corrosion Mechanisms,”page 8), so any mechanical measures toreduce stress such as decreasing torque orweight-on-bit will limit this type of failure.Surprisingly, high temperature reduces sul-fide stress cracking. So if H2S is detected, itis better to take advantage of high downholetemperatures and treat the mud with thedrillstring in the hole.

Corrosion control of CO2 is similar to H2Scontrol in that pH must be raised to reducethe acid effects, and drillpipe should becoated with inhibitors. Carbon dioxide canenter the mud system several ways—directlyfrom the formation, by thermal degradationof organic materials, as carbonates frombarite or bentonite, chemical over-treatmentwith soda ash, or bicarbonate of soda. Cal-cium hydroxide can be used to precipitatecarbonates to reduce CO2 levels.

Completion—After casing has been putin a well, it is usually cemented in place.Cement itself provides primary externalprotection against corrosion, especiallynear the surface where circulating aquiferwater supplies unlimited oxygen. As arecent study on casing leaks in the Wafrafield in Kuwait discovered, the type ofcement used is also important. Severe cor-rosion occurred in wells where construc-tion and permeable light cement were usedinstead of the usual Portland class Gcement with additives.11 Leakage rates werehigher in shallow zones where high sulfateconcentrations caused the constructioncement—which is nonsulfate resistant—tobreak down, exposing the exterior of thecasing to corrosive aquifer water.

Completion design also plays an impor-tant role in preventing internal corrosion.Reducing sand production by gravel pack-

11April 1994

nComparison ofcorrosion rates ofsteel. Measure-ments of the corro-sion rates of a car-bon steel exposedto different con-centrations of O2,CO2 and H2S gasesdissolved in water,show that O2 isabout 80 timesmore corrosivethan CO2 and 400times more corro-sive than H2S.

nLocalized bacterial corrosion. Colonies of sulfate-reducing bacteria (SRB) form a deposit under which crevice corrosiondevelops. The SRBs introduce H2S into the system, which causesthe corrosion.

9. ASM Handbook, reference 1: 1258-1259.Jones, reference 1: 61-63.

10. Triazine compounds are derived from carbon,hydrogen and nitrogen compounds based onC3H3N3 rings.

11. Bazzari JA: “Well Casing Leaks History and Corro-sion Monitoring Study, Wafra Field,” paper SPE17930, presented at the SPE Middle East Oil Techni-cal Conference and Exhibition, Manama, Bahrain,March 11-14, 1989.Harari ZY: “Monitoring Short-Term Corrosion Ratesin Some Oilwell Cements,” Journal of PetroleumTechnology 42, no. 4 (April 1990): 418-421, 479.

25

20

15

10

5

0

Ove

rall

corr

osio

n ra

te o

f car

bon

stee

l, m

il/yr

1 2 3 4 5 6 7 8O2

Dissolved gas concentration in water phase, ppm

O2

H2S

CO2

50 100 150 200 250 300 350 400CO2100 200 300 400 500 600 700 800H2S

O2

Metal substrate

Weld metal

Localized corrosion

O2

Sulfate-reducing bacteria

ing prevents sand blasting that causes ero-sion corrosion. Erosion corrosion will bemore pronounced on equipment thatrestricts flow such as nipples, valves orsharp pipe bends. Once erosion hasremoved protective coatings, other forms ofcorrosion can start. The velocity of pro-duced fluids has the same effect as pro-duced sand with erosion occurring at placesof turbulence and cavitation.

Stimulation programs may, inadvertently,promote internal corrosion. Depending onlithology, highly corrosive hydrochloric acid[HCl] with additions of hydrofluoric [HF]acid are used to improve near-wellbore per-meability. These acids can also remove scalebuildup on the inside of casing and tubing,allowing direct attack on bare metal. (Scale,produced by iron sulfide and iron carbonatedeposits, restricts the corrosion process.Other types of scale are porous and do notprotect.) It is therefore essential to useinhibitors and to flow the well to removespent acid and allow pH levels to increase.

Inhibitors are mixed with acid to providea protective film over exposed completionstrings.12 The first generation of acidinhibitors was based on highly poisonousarsenic products, but over the years lesstoxic and more environmentally appropri-ate products have been developed. TheCORBAN range of inhibitors produced byDowell are designed for acid inhibition ofmost oilfield tubulars, including coiled tub-ing, duplex steels and other exotic alloys atup to 400 °F [200 °C].

The type and amount of inhibitor used—inhibitor loading—depends not only on theacid and its strength, but also on the metalit is protecting, the working temperaturerange and the protection time desired.Inhibitor loadings are determined by mea-suring the corrosion of samples of casing ortubing—coupons—in a corrosion-test auto-clave that duplicates the well-treatingenvironment.

Corrosion during production—Corrosioncan continue inside the casing and alongcompletion strings and pipelines during thelife of a well. Gas condensate wells may pro-duce gas, hydrocarbons, formation water,acid gases (CO2 and H2S) and organic

Caliper Devices

Mechanical multifinger calipers have been used

for many years to measure the internal diameter

of tubing and casing. The Tubing Geometry

Sonde (TGS) tool has interchangeable 16-finger

sections covering tubing sizes from 2 7/8 to 7 in.

[7 to 18 cm]. The larger MultiFinger Caliper

(MFC) tool has interchangeable sections with 36,

60 and 72 arms covering casing sizes from 7 to

13 3/8 in. [18 to 34 cm]. Both tools can be run in

any borehole fluid and are able to measure small

holes as long as a caliper passes over them. Log

presentations vary and may be quite sophisti-

cated (above).

Corrosion Rate Devices

The CPET Corrosion and Protection Evaluation

Tool has four sets of three electrodes, spaced at

2-ft [60-cm] intervals along the tool (next page).

The tool takes stationary measurements of poten-

tial differences and casing resistance between

electrode pairs. Casing current is calculated from

these measurements at each depth. By taking the

difference in current between stations, the radial

current density can be calculated and the corro-

sion rate computed. Casing thickness can also be

derived by assuming casing conductivity and

using the nominal casing outside diameter. A plot

of casing current flow against depth, shows

anodic regions where corrosion is likely to occur.

If the well is cathodically protected, the log will

also show the efficiency of the protection. The

tool can be run successively after adjustment of

the cathodic protection system current to ensure

that anodes have been biased out.12

Corrosion Logging Tools

nMultiFinger Caliper logfrom the North Sea. Thislog shows the 16 calipersfrom the Tubing GeometrySonde multifinger caliper(middle track). An imageof metal loss (right-handtrack) shows severe corro-sion at X54 ft.

12. Frenier WW, Hill DG and Jansinski RJ: “CorrosionInhibitors for Acid Jobs,” Oilfield Review 1, no. 2(July 1989): 15-21.Crowe C, Masmonteil J, Thomas R and Touboul E:“Trends in Matrix Acidizing,” Oilfield Review 4, no. 4 (October 1992): 24-40.Samant AK, Koshel KC and Virmani SS, “Azoles asCorrosion Inhibitors for Mild Steel in a HydrochloricAcid Medium,” paper SPE 19022, 1988.

Metal Loss %-25 0 20 70

Internal Radii

Dep

th, f

t Maxpit.%

Casing Geometry

X40

X50

X60

X70

nCPET Corrosion and Protection Evaluation Tool. The CPET tool has four sets of three electrodes, each one atthe end of a hydraulically operated arm. Stationary readings (inset) are taken and 12 separate contact resis-tances and electrode potential differences are measured.

A1

A3

B1

C1

D1

B3

C3

D3

A2

B2

C2

D2

Electronic cartridge

Telemetry cartridge

Hydraulic section

Electrodes

Stationary readings

Electromagnetic Devices

The METT Multifrequency Electromagnetic Thick-

ness Tool is used to detect large-scale corrosion.

It works on the same principle as an induction

tool, having a transmitter coil and a receiver coil.

The transmitter generates an alternating mag-

netic field that induces eddy currents in the cas-

ing. These produce a secondary magnetic field

that interferes with the primary field causing a

phase shift. This is detected by the receiver coil.

The phase shift is proportional to the total

amount of metal surrounding the tool and hence

April 1994

the thickness of the casing. By using a multifre-

quency transmitter, other properties of the casing

that also affect the phase shift can be measured

so that thickness can be calculated. An internal

caliper measurement is derived from a high-fre-

quency field that penetrates the casing skin only.

The casing inside diameter (ID) measurement is

not affected by nonmagnetic scale deposits. Mon-

itoring a well over several years using the METT

tool gives the general corrosion rate.

The PAL Pipe Analysis Log tool measures mag-

netic flux leakage anomalies on the casing wall.

Low-frequency magnetic flux is generated by an

electromagnet, and pad-mounted sensors detect

the anomalies. Inner wall defects are detected by

inducing surface eddy currents using a separate

coil array with a high-frequency signal. This

helps to distinguish internal from external

defects. The PAL tool is primarily used to detect

casing holes.

The FACT Flux Array Corrosion Tool works on

the same principle as the PAL tool, but has a

more powerful electromagnet and is designed to

negotiate bends down to three times the pipe

diameter (3D bends).

Ultrasonic Devices

The USI UltraSonic Imager tool and the CET

Cement Evaluation Tool use ultrasonic sound

pulses that reflect off and resonate within the

casing wall. The transit time of the first received

echo gives the internal casing radius. Frequency

analysis of the resonant portion of the signal pro-

vides casing thickness, allowing internal and

external metal loss to be computed. The CET tool

has eight transducers equally spaced in a helix

around the tool to give a limited casing cover-

age. The more advanced USI tool has a single

rotating transducer to provide full coverage. The

13

nComposite corrosion log. Three corrosion toolshave provided the data for this composite log. Track1 shows the nominal casing ID and OD along withthe ID and OD from the CET Cement Evaluation Tooland indicates the presence of corrosion, or scale orwax buildup. Track 2 shows the total metal loss fromthe METT Multifrequency Electromagnetic ThicknessTool. Track 3 shows the well sketch along with a flagif the corrosion is more than 50%. Track 4 shows theincrease or decrease in radius images generatedfrom the eight transducers of the CET tool. Track 5shows the increase or decrease in casing thicknessfrom the CET tool. Track 6 shows roughness image,again from the CET tool, to indicate the presence ofpitting or scale. Track 7 gives casing geometry infor-mation from the CET tool. Track 8 gives defect identi-fication from the PAL Pipe Analysis Log tool. Thecoding has been accepted by the National Associa-tion of Corrosion Engineers (NACE) and the EnergyResources Conservation Board (ERCB) in Canada.Code 2 means 20 to 40% of wall penetration; code 3,40 to 60% wall penetration; code 4, 60 to 80% wallpenetration; inner defect means over 20% wall pene-tration and penetration means a potential hole.

14

Casing ID

-7 in. 3OD

-9 in. 1Radius

Thickness

Eccentering0 in. 0.5

Rel Bearing0 deg 360

Deviation0 deg 360

5-10% gain

0-5% loss

10-15% loss

above 25%Met

al L

oss

Inne

r de

fect

Cod

e 2

Cod

e 3

Cod

e 4

Pen

etra

tion

Wel

l Ske

tch

Thickness RoughnessInner Radii

1-.9

.7-.6

.2-.1

–0

Defectcode from

PAL

acids.13 Wells that produce formation water,or allow it to condense, are likely to cor-rode; this may occur anywhere in the tubingstring, wellhead or flowline. Higher temper-atures accelerate the corrosion rate, as doesfaster flow. Corrosion increases with watersalinity up to about 5% of sodium chloride.Above this, the solubility of oxygen in thewater decreases reducing corrosion rates. Infact, when the salt content is above 15%,the rates are lower than with fresh water(next page, top). When water and acidgases are present, the corrosion rates riserapidly. Water dissolves CO2 or H2S andbecomes acidic.

In highly corrosive environments, carbonsteel can be protected by corrosioninhibitors during production.14 Like acidcorrosion inhibitors, these adhere to casingand completion strings to form a protectivefilm. Inhibitors can be continuously intro-duced into a producing well by a capillarytube run on the outside of the tubing as partof the completion design (next page, right).Other methods include batch treatmentwhere inhibitor is pumped down the tubingregularly, say every six weeks, or squeezetreatments, where inhibitor is pumped intothe formation.

To protect wells and pipelines from exter-nal corrosion, cathodic protection is used.15

In remote areas sacrificial ground beds maybe used for both wells and pipelines (nextpage, left). A single ground bed can protectup to 50 miles [80 km] of pipeline. In theMiddle East, solar panels have been used topower impressed current cathodic protec-tion systems. Other methods include ther-moelectric generators fueled directly fromthe pipeline. To protect several wells, a cen-tral generator may be used and a distribu-

13. Gunaltun Y: “Carbon Dioxide Corrosion in OilWells,” paper SPE 21330, presented at the SPE Middle East Oil Show, Manama, Bahrain, November16-19, 1991.Crolet J-L and Bonis MR: “Prediction of the Risks of CO2 Corrosion in Oil and Gas Wells,” paper SPE20835, presented at the Offshore Technology Con-ference, Houston, Texas, USA, May 7-10, 1990.

14. Argent CJ, Kokoszka CL, Dale MJ and HindmarshMW: “A Total System Approach to Sweet Gas Corrosion Control by Inhibition,” paper SPE 23153,presented at the Offshore Europe Conference,Aberdeen, Scotland, September 3-6, 1991.Stephens RM and Mohamed MF: “Corrosion Moni-toring and Inhibition in Khuff Gas Wells,” paper SPE 11511, presented at the SPE Middle East OilTechnology Conference, Manama, Bahrain, March14-17, 1983.

15. Seubert MK: “Design Parameters for Offshore Well

CET and USI tools were developed to record cement

bond and inspect the casing.

The Borehole Televiewer (BHTV) tool, Acoustic

TeleScanner (ATS) and the UBI Ultrasonic Borehole

Imager tool were all developed for openhole appli-

cations and employ a rotating transducer. The ATS

and UBI tools use a focused transducer to show

much finer detail than the CET or USI tools.

All acoustic tools are affected by dense highly

attenuating muds and casing scale. They also, at

present, do not work in gas-filled holes.

Composite Logs

Many corrosion tools can be combined to give a

detailed picture of internal or external corrosion,

general corrosion or pits and holes. Modern com-

puters can present these data in many different

ways according to customer requirements (above).

Oilfield Review

Casing Cathodic Protection,” paper SPE 17934, presented at the SPE Middle East Oil Technical Conference and Exhibition, Manama, Bahrain,March 11-14, 1989.

nCorrosive effects of sodium chloride [NaCl]. As the weight per-centage of NaCl increases up to about 5%, the corrosion rateincreases rapidly. Increasing the salt content above this reducesthe solubility of oxygen, so the corrosion rate decreases and atabout 15% NaCl, the rate is less than with fresh water.

nTypical cathodicprotection installa-tion for a pipeline.Sacrificial anodesare buried deepunderground in ahole filled withconductive mate-rial to ensure elec-trical continuitybetween theanodes throughthe ground to thepipeline. The cir-cuit is completedby connecting acable through arectifier to thepipeline. The recti-fier ensures thatthe cathodic pro-tection systemdoes not reverse,causing thepipeline to corrode.

nCapillary tube inhibitor injection.Inhibitors are chemicals that are absorbedonto a metal surface from solution to pro-tect against corrosion. The protective filmslows corrosion by increasing anodic andcathodic polarization, reducing diffusion ofions to the metal surface, increasing theelectrical resistance at the metal-elec-trolyte interface and by increasing thehydrogen over voltage—the voltagerequired to remove hydrogen and preventa buildup stifling the corrosion process. The choice of inhibitor depends on themetal to be protected and its environment.Equally important is the method of appli-cation. Shown is a continuous injectionmethod to protect tubing. Inhibitor ispumped down a capillary tube strapped to the outside of the tubing to a side pocketmandrel where it will then mix with pro-duction fluid and form a protective film onthe inside.

15April 1994

2.5

2

1.5

1

0.5

05 10 15 20 25

Rel

ativ

e co

rros

ion

rate

% NaCI by weight

Wellhead

Inhibitor injection capillary tube

Clamp

Side pocketmandrel

Packer

Tubing

Pipe casing through loose surface soils

Vented and secured casing cap

Medium gravel to hold hole open and vent any gases

Working portion of ground bed

Anode strapped to pipe support

Conductive material

Pipe foot

Centering device

Protected pipeline

Rectifier

Pipe support

Cabled individual anode leads

– +

16

Sonde

Compensating device

Motor assembly

Gear box assembly

Rotating electrical connection

Centralizer

Rotating shaft with built-in electronics

Rotating seal

Transducer

Interchangeable rotating sub

7.5 rps

Plastic InsulatorSteel ring

Test coupon

Drillpipe

Tool joint

nThe UBI Ultrasonic Borehole Imager tool.The UBI tool uses a rotating focused trans-ducer to produce an image of the casing.The transducer fires an ultrasonic pulse atthe casing. Some energy is reflected backto the transducer from the internal surfaceof the casing. By measuring the timebetween transducer firing and the arrivalof the first echo an accurate casing inter-nal diameter is calculated. The amplitudeof the first arrival also gives a vivid imageof the inner casing surface. The tool has a

nTest coupon for monitoring corrosion ofdrillpipe. Test coupons may be inserted inany type of pipe work to monitor corrosion.Rings inserted in the tool joints of drillpipeare later removed and examined to moni-tor corrosion type and corrosion rate—theassumption being that the coupons cor-rode at the same rate as the drillpipe.Mud engineers also use drillpipe couponsto check the corrosive properties of themud system.

tion network set up. Wells should be insu-lated from pipelines so that protection sys-tems do not cause unwanted anodic regionsand stray current corrosion.

Under the right conditions, iron sulfideand iron carbonate scales—the corrosionproducts when H2S or CO2 are present—provide protective coatings. The composi-tion of production fluids, however, maychange during the life of a reservoir so rely-ing on natural protection may not be wise.Corrosion monitoring, in some form, shouldalways be undertaken.

Monitoring CorrosionCorrosion monitoring is just as important asrecognizing the problem and applying con-trols. Monitoring attempts to assess the use-ful life of equipment, when corrosion condi-tions change and how effective the controlsare. Techniques used for monitoring dependon what the equipment is, what it is used forand where it is located.

Structures—Monitoring corrosion onexposed structures is fairly straightforwardand is carried out by visual inspection. Morerigorous tests are required when a structureis load-bearing. Some form of nondestructivetesting is used, such as magnetic particletesting to reveal cracks.16 Sedco Forex rigsare inspected every four years and requireunderwater divers or remote operated vehi-cles (ROVs) using still or video photographyto check the condition of legs and risers.During this inspection the corrosion rate ofsacrificial anodes can be assessed. Normallyanodes are designed to last seven or eightyears so they will have to be replaced duringthe typical 20-year life of a rig.

Drillpipe—To monitor drillpipe corrosionand the effectiveness of mud treatments,coupon rings are installed between joints(left ). The rate of corrosion can then beassessed by measuring the amount of metallost from the rings. Rates of 0.5 to 2lbm/ft2/yr [2.4 to 9.8 kg/m2/yr] without pit-ting are acceptable. Drillpipe is also regu-larly inspected on racks by ultrasonic and X-ray techniques.

Mud—During drilling, mud systems areroutinely monitored for chemical and physi-cal properties. Tests specifically related tocorrosion control include an analysis ofoxygen, CO2, H2S and bacteria. Hydrogensulfide is detected by measuring the total

Oilfield Review

vertical resolution of 0.2 in. [5 mm].

nUBI log in casedhole. This log ispresented on ascale of 1:10 andshows a large holein the 7-in. lineraround X220 ft.Just above the cor-roded hole is a pat-tern of severalsmaller holeswhere the casinghas been perfo-rated. Track 1shows the ampli-tude image, Track2 the increase ordecrease in theinternal radiusimage and Track 4shows the metalloss image. Track 3gives a cross sec-tion of the well.

16. Barreau et al, reference 7.17. Bettis FE, Crane LR, Schwanitz BJ and Cook MR:

“Ultrasound Logging in Cased Boreholes PipeWear,” paper SPE 26318, presented at the 68th SPEAnnual Technical Conference and Exhibition, Hous-ton, Texas, USA, October 3-6, 1993.Kolthof WJ and van der Wal D: “The Use of Digi-

18. Fincher DR and Nestle AC: “A Review of CorrosionMonitoring Techniques,” paper SPE 4220, presentedat the Symposium on the Handling of OilfieldWaters of the SPE of AIME, Los Angeles, California,USA, December 4-5, 1972.Galbraith JM: “In-Service Corrosion Monitoring WithAutomated Ultrasonic Testing Systems,” paper SPE

Amplitude, dB

X220

X212

X228

Internal Radiiminus avg, in.

Metal Loss, in.

perforations

Radiusmin.

max.

avg, in.

2.5 in 3.5

0 7 11 15 –0.1

500

–0.0

711

0.08

68

0.15

–0.5

–0.1

842

0.18

42

0.5

level of soluble sulfides. Mud filtrate can betested further by adding acid to liberate H2S,which can be measured using any standardH2S detector such as a Draeger tube. Bacte-rial attacks can be recognized by a drop inpH, increase in fluid loss or change in vis-cosity. Anaerobic bacteria can turn the mudblack and produce a smell of rotten eggs.

Casing and tubing—Various corrosionlogging tools measure internal corrosion,external corrosion and even evaluatecathodic protection of oil wells (see “Corro-sion Logging Tools” page 12).17 One of themost commonly used techniques has beenthe multifinger caliper run on either slicklineor electric line. This measures the internalradius of casing and tubing using lightlysprung feeler arms. (Heavy springing cancause the fingers to leave tracks throughprotective scales and chemical inhibitorsleading to enhanced corrosion from runningthe survey itself!) An improvement on con-tact calipers is the ultrasonic caliper (previ-ous page, right), which uses a rotating ultra-sonic transducer to measure the echo timeof a high-frequency sonic pulse. The pro-cessed signal produces a map of the casing.A recent development using a speciallyfocused transducer designed for open holeand currently under development for casedhole, shows remarkable cased hole detail(right). The perforations are clearly seen.

Wireline logging provides a good evalua-tion of downhole corrosion, but disruptsproduction and may involve pulling com-pletions. Oil companies, therefore, like touse surface monitoring methods to indicatewhen downhole inspection is required.

Pipelines—Surface monitors include testcoupons placed at strategic points in theflowline and also more sophisticated tech-niques that attempt to measure corrosionrates directly (resistance devices, polariza-tion devices, galvanic probes, hydrogenprobes and iron counts).18 This approach tomonitoring can be hit or miss when trying torelate surface corrosion to downhole corro-

17April 1994

tised Tubing Caliper Data for Workover Planning,”paper SPE 23134, presented at the Offshore EuropeConference, Aberdeen, Scotland, September 3-6,1991.Cryer J, Dennis B, Lewis R, Palmer K and Watfa M:“Logging Techniques for Casing Corrosion,” TheTechnical Review 35, no. 4 (October 1987): 32-39.Davies DH and Sasaki K: “Advances in Well CasingCathodic Protection Evaluation,” Materials Perfor-mance 28, no. 8 (August 1989): 17-24.

22097, presented at the International Arctic Technol-ogy Conference, Anchorage, Alaska, USA, May 29-31, 1991.

sion. In the past, the onset of well problemsinstigated monitoring. While waiting for afailure is not recommended, recovering cor-roded tubing or casing at least providesvaluable after-the-fact information, andevery opportunity is taken to find out whatcaused the corrosion and the failure.

Some downhole monitoring techniqueshave been adapted to logging pipelines.19

The same surface logging equipment isused, but the logging tools themselves havebeen made more flexible to pass aroundsharp bends (right ). Short lengths of pipemay be logged by this method, but longerlengths are usually monitored by smart pigs.These are sophisticated instrument pack-ages, which use ultrasonic, flux leakage andother electromagnetic techniques to checkfor corrosion. The data are usually stored inthe pig itself for later retrieval. The pig ispumped along a pipeline from a specially-built launching station to a purpose-builtreceiving section of the pipeline. Surveyscover tens or even hundreds of miles.

ConclusionThe oil industry has invested heavily inmaterial and personnel to try to tame corro-sion and prevent metal from returning to itsnatural state. New oil fields benefit frompredevelopment planning and the growingknowledge of all aspects of corrosion con-trol and monitoring. Older fields will con-tinue to benefit from the expertise of thecorrosion engineer and the constant moni-toring required to prevent disaster. —AM

nThe FACT FluxArray Corrosion Tool.This highly articu-lated sensor mea-sures flux leakageand eddy currentanomalies associ-ated with pit orcrevice corrosion on pipeline walls. A powerful electro-magnet generateslow-frequency mag-netic flux. Corrosioncauses changes inthe flux, inducing a voltage in the pad-mounted sensor coils.Separate coils detectinner wall defects by inducing surfaceeddy currents with ahigh-frequency sig-nal. This helps distin-guish internal fromexternal defectsdetected by the fluxleakage coils.

18 Oilfield Review

19. Edwards RC: “Pipeline Corrosion Logging: A NewApplication of Wireline Surveys,” paper SPE 17743,presented at the SPE Gas Technology Symposium,Dallas, Texas, USA, June 13-15, 1988.

Electronics

Pad-mounted sensorsand electromagnet

3D Seismic Survey Design

There’s more to designing a seismic survey than just choosing sources and receivers and shooting away. To

get the best signal at the lowest cost, geophysicists are tapping an arsenal of technology from integration of

borehole data to survey simulation in 3D.

April 1994

For help in preparation of this article, thanks to JackCaldwell and Greg Leriger, Geco-Prakla, Houston, USA;Mandy Coxon and Dominique Pajot, Geco-Prakla,Gatwick, England; Jacques Estival, Elf Petroleum Nigeria,Lagos, Nigeria; Dietmar Kluge, Geco-Prakla, Hannover,Germany; Lloyd Peardon, Schlumberger CambridgeResearch, England; Lars Sonneland, Geco-Prakla, Stavanger, Norway; and Tim Spencer, British Gas, Reading, England.Appreciation is expressed to Qatar General PetroleumCorporation (QGPC) for its consent to the release of data.QUAD-QUAD is a mark of Geco-Prakla. TWST(Through-Tubing Well Seismic Tool) is a mark of Schlum-berger.1. For the most recent worldwide figures:

Riley DC: “Special Report Geophysical Activity in1991,” The Leading Edge 12, no. 11 (November1993): 1094-1117.

2. Personal communication: Thor Sinclair.

C. Peter AshtonMærsk Olie og Gas ASCopenhagen, Denmark

Brad BaconAngus MannNick MoldoveanuHouston, Texas, USA

Christian DéplantéElf AquitainePau, France

DickiIresonThor SinclairGatwick, England

Glen Redekop Maersk Oil Qatar ASDoha, Qatar

nCost of marine 3Dseismic surveys forone oil company.Since 1990, the costof a marine 3D sur-vey has decreasedby more than 50%.(Courtesy of Ian Jack,BP Exploration, Stock-ley Park, England.)

Dol

lars

, in

thou

sand

s

Cost of Marine 3D Seismic Survey per km2

40

35

30

25

20

10

5

0

15

1990 1991 1992 1993

Year

Increased efficiency has brought the cost ofmarine three-dimensional (3D) seismic datato its lowest level ever, expanding the popu-larity of 3D surveys (above). In the past fiveyears, oil companies have increased expen-ditures on seismic surveys by almost 60%,to $2.2 billion.1 However, an estimated10% of surveys fail to achieve their primaryobjective—some because the technologydoes not exist to process the data, somebecause the surveys are improperlyplanned.2 Careful planning can result inmore cost-effective acquisition and process-ing, and in data of sufficient quality to bene-fit from the most advanced processing.

But before the first shot is fired or the firsttrace recorded, survey designers must deter-mine the best way to reveal the subsurfacetarget. As basics, they consider locationsand types of sources and receivers, and thetime and labor required for acquisition.Many additional factors, including health,safety and environmental issues, must be

taken into account. This article investigatesthe objectives and methods of seismic sur-vey design and reviews field examples ofstate-of-the-art techniques.

The ideal 3D survey serves multiple pur-poses. Initially, the data may be used toenhance a structural interpretation based ontwo-dimensional (2D) data, yielding newdrilling locations. Later in the life of a field,seismic data may be revisited to answerquestions about fine-scale reservoir architec-ture or fluid contacts, or may be comparedwith a later monitor survey to infer fluid-frontmovement. All these stages of interpretationrely on satisfactory processing, which in turnrelies on adequate seismic signal to process.The greatest processing in the world cannotfix flawed signal acquisition.

19

20

nTemporal andspatial aliasingcaused by sam-pling less thantwice per cycle.Temporal aliasing(top) occurs wheninsufficient sam-pling renders a 50-Hz signal and a200-Hz signal indis-tinguishable(arrows representsample points). The50-Hz signal is ade-quately sampled,but not the 200-Hz.(Adapted from Sheriff,reference 4.) Spatialaliasing (bottom)occurs whenreceiver spacing ismore than half thespatial wavelength.With minor aliasing(left) arrivals can betracked at near off-sets as timeincreases, butbecome difficult tofollow at far offsets.With extreme alias-ing (right) arrivalseven appear to betraveling back-wards, toward nearoffsets as timeincreases. (Adaptedfrom Claerbout, refer-ence 6.)

nBetter stacking from a wide and evenly spaced set of offsets.Reflection arrival times from different offsets are assumed to fol-low a hyperbola. The shape of the hyperbola is computed fromthe arrivals. Traces are aligned by flattening the best-fittinghyperbola into a straight line, then summed, or stacked. Perfectalignment should yield maximum signal amplitude at the timecorresponding to zero offset. A wide range of evenly spaced off-sets gives a better-fitting hyperbola, and so a better stack.

200 Hz50 Hz

Time, msec0 8 16 24 32

Temporal Aliasing

Stackingvelocity+ =

Hyperbolicmoveout

Offset

Two-

way

tim

e

Offset

CMP gather CorrectedCMP gather

StackedCMP trace

+ + =

Two-

way

tim

e

Increasing offset

Minor Aliasing Extreme Aliasing

Increasing offset

Elements of a Good SignalWhat makes a good seismic signal? Process-ing specialists list three vital require-ments—good signal-to-noise ratio (S/N),high resolving power and adequate spatialcoverage of the target. These basic elements,along with some geophysical guidelines (see“Guidelines from Geophysics,” page 22),form the foundation of survey design.

High S/N means the seismic trace hashigh amplitudes at times that correspond toreflections, and little or no amplitude atother times. During acquisition, high S/N isachieved by maximizing signal with a seis-mic source of sufficient power and directiv-ity, and by minimizing noise.3 Noise caneither be generated by the source—shot-generated or coherent noise, sometimesorders of magnitude stronger than deep seis-mic reflections—or be random. Limitationsin the dynamic range of acquisition equip-ment require that shot-generated noise beminimized with proper source and receivergeometry. Proper geometry avoids spatialaliasing of the signal, attenuates noise andobtains signals that can benefit from subse-quent processing. Aliasing is the ambiguitythat arises when a signal is sampled lessthan twice per cycle (left). Noise and signalcannot be distinguished when their sam-pling is aliased.

A common type of coherent noise thatcan be aliased comes from low-frequencywaves trapped near the surface, called sur-face waves. On land, these are known asground roll, and create major problems forprocessors. They pass the receivers at amuch slower velocity than the signal, andso need closer receiver spacing to be prop-erly sampled. Planners always try to designsurveys so that surface waves do not con-taminate the signal. But if this is not possi-ble, the surface waves must be adequatelysampled spatially so they can be removed.

During processing, S/N is enhancedthrough filters that suppress noise. Coherentnoise is reduced by removing temporal andspatial frequencies different from those ofthe desired signal, if known. Both coherentand random noise are suppressed by stack-ing—summing traces from a set of source-receiver pairs associated with reflections ata common midpoint, or CMP.4 The source-receiver spacing is called offset. To bestacked, every CMP set needs a wide andevenly sampled range of offsets to define thereflection travel-time curve, known as thenormal moveout curve. Flattening thatcurve, called normal moveout correction,will make reflections from different offsetsarrive at the time of the zero-offset reflec-tion. They are then summed to produce astack trace (left ). In 3D surveys, with the

nReflections from source-receiver pairs bounce in a bin, a rectan-gular, horizontal area defined during planning. In a 3D survey aCMP trace is formed by stacking traces that arrive from a range ofazimuths and offsets (top). The distribution of offsets is displayed ina histogram within each bin (bottom). The vertical axis of the his-togram shows the amount of offset, and the horizontal axis indi-cates the position of the trace in offset.

1 2 3

4 5 6

1 2 3

4 5 6

Offsets and Azimuths in a CMP Bin

Offset DistributionSource ReceiverBin

130

160

190

220

250

Shotpoint number130 160 190 220

Fold

3

7

11

14

18

22

25

29

33

36

40

advent of multielement marine acquisi-tion—multistreamer, multisource seismicvessels—and complex land acquisitiongeometries, reflections at a CMP come froma range of azimuths as well as a range ofoffsets (right).5 A 3D CMP trace is formed bystacking traces from source-receiver pairswhose midpoints share a more or less com-mon position in a rectangular horizontalarea defined during planning, called a bin.The number of traces stacked is calledfold—in 24-fold data every stack trace rep-resents the average of 24 traces. Theoreti-cally, the S/N of a survey increases as thesquare root of the fold, provided the noise israndom. Experience has shown, however,that for a given target time, there is an opti-mum fold, beyond which almost no S/Nimprovement can be made.

Many survey designers use rules of thumband previous experience from 2D data tochoose an optimal fold for certain targets orcertain conditions. A fringe—called the foldtaper or halo—around the edge of the sur-vey will have partial fold, thus lower S/N,because several of the first and last shots donot reach as many receivers as in the centralpart of the survey (below, right). Getting fullfold over the whole target means expandingthe survey area beyond the dimensions ofthe target, sometimes by 100% or more.Many experts believe that 3D surveys do notrequire the level of fold of 2D surveys. Thisis because 3D processing correctly positionsenergy coming from outside the plane con-taining the source and receiver, which in the2D case would be noise. The density of datain a 3D survey also permits the use of noise-reduction processing, which performs betteron 3D data than on 2D.

Filtering and stacking go a long waytoward reducing noise, but one kind ofnoise that often remains is caused by multi-ple reflections, “multiples” for short. Multi-ples are particularly problematic wherethere is a high contrast in seismic propertiesnear the surface. Typical multiples are rever-berations within a low-velocity zone, suchas between the sea surface and sea bottom,

21April 1994

nA fold plot showing 40-fold coverage over the heart of the survey.The edge of the survey has partial fold because several of the firstand last shots do not reach as many receivers as in the central partof the survey.

3. Directivity is the property of some sources wherebyseismic wave amplitude varies with direction.

4. For a full description of terms used in seismic data processing see Sheriff RE: Encyclopedic Dictionary ofExploration Geophysics. Tulsa, Oklahoma, USA: Soci-ety of Exploration Geophysicists, 1991.

5. Streamers are cables equipped with hydrophonereceivers. Multistreamer vessels tow more than onereceiver cable to multiply the amount of data acquiredin one pass. For a review of marine seismic acquisitionand processing see Boreham D, Kingston J, Shaw Pand van Zeelst J: “3D Marine Seismic Data Process-ing,” Oilfield Review 3, no. 1 (January 1991): 41-55.

nSeismic section with strong multiple noise. Multiples canappear as a repetition of a shallower or deeper portion of theseismic image. [Adapted from Morley L and Claerbout JF: “Predic-tive Deconvolution in Shot-Receiver Space,” Geophysics 48 (May 1983):515-531.]aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaPrimary

reflection GhostNear-surface

multiples Long-pathmultiple

nMultiple reflec-tions. After leav-ing the source,seismic energycan be reflected anumber of timesbefore arriving atthe receiver.

22

Tim

e, s

ec

Seafloor reflection

Seafloor multiple

Seafloor multiple

Primary reflection

Multiple

Multiple4.0

3.0

2.0

1.0

0

or between the earth’s surface and the bot-tom of a layer of unconsolidated rock(below, left). Multiples can appear as laterarrivals on a seismic section, and are easy toconfuse with deep reflections (left ).6 Andbecause they can have the same character-istics as the desired signal—same frequencycontent and similar velocities—they areoften difficult to suppress through filteringand stacking. Sometimes they can beremoved through other processing tech-niques, called demultiple processing, butresearchers continue to look for better waysto treat multiples.

The second characteristic of a good seis-mic signal is high resolution, or resolvingpower—the ability to detect reflectors andquantify the strength of the reflection. This isachieved by recording a high bandwidth, orwide range of frequencies. The greater thebandwidth, the greater the resolving powerof the seismic wave. A common objective ofseismic surveys is to distinguish the top andbottom of the target. The target thicknessdetermines the minimum wavelengthrequired in the survey, generally consideredto be four times the thickness.7 That wave-length is used to calculate the maximumrequired frequency in the bandwidth—average seismic velocity to the targetdivided by minimum wavelength equalsmaximum frequency. The minimum fre-quency is related to the depth of the target.Lower frequencies can travel deeper. Someseismic sources are designed to emit energyin particular frequency bands, and receiversnormally operate over a wider band. Ideally,sources that operate in the optimum fre-quency band are selected during surveydesign. More often, however, surveys areshot with whatever equipment is proposedby the lowest bidder.

Guidelines from Geophysics

Many of the rules that guide 3D survey design are

simple geometric formulas derived for a single

plane layer over a half-space: the equation

describing the hyperbola used in normal moveout

correction is one example. Others are approxima-

tions from signal processing theory. Sometimes

survey parameters are achieved through trial and

error. The following formulas hold for some sim-

ple 3D surveys:

Bin size, ∆x∆y, is calculated to satisfy vertical

and lateral resolution requirements. For a flat

reflector, bin length, ∆x, can be the radius of the

Fresnel zone or larger. The Fresnel zone is the

area on a reflector from which reflected energy

1. Normal moveout stretch is the distortion in wave-

can reach a receiver within a half-wavelength of

the first reflected energy. For a dipping reflector

where Vrms is the root mean square average of

velocities down to the target, fmax is the maxi-

mum nonaliased frequency required to resolve

the target, and ϑ is the structural dip. Normally

∆y = ∆x.

3D fold is determined from estimated S/N of

previous seismic data, usually 2D. 3D fold must

be greater than or equal to

∆x = V rms

4f max sin ϑ ,

2D fold ∆x∆y2Rf dx

,

where Rf is the radius of the Fresnel zone and dx

is the CMP interval in the 2D data.

Maximum offset, Xmax, is chosen after consid-

ering conflicting factors—velocity resolution,

normal moveout stretch and multiple

attenuation.1 For a velocity resolution ∆v/v

required to distinguish velocities at time T,

where ∆f is fmax − fmin, or the bandwidth. As Xmax

increases, ∆v/v increases, or improves. But with

long offsets, normal moveout stretch increases

and multiples can become worse.

Xmax = 2Tv2

∆f ∆vv

,

shape caused by normal moveout correction.

nEffect of reflector dip on the reflection point. When the reflector isflat (top) the CMP is a common reflection point. When the reflectordips (bottom) there is no CMP. A dipping reflector may requirechanges in survey parameters, because reflections may involvemore distant sources and receivers than reflections from a flat layer.

6. Claerbout JF: Imaging the Earth’s Interior. Boston,Massachusetts, USA: Blackwell Scientific Publications(1985): 356.

7. This is the criterion for resolving target thickness visu-ally. By studying other attributes of a seismic tracesuch as amplitude or signal phase, thinner layers canbe resolved.

8. Survey design and survey planning are sometimesused interchangeably, but most specialists prefer tothink of planning as the part of the design process thatconsiders cost constraints and logistics.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaHorizontal Reflector

Dipping Reflector

ShotpointReceiver

23April 1994

Another variable influencing resolution issource and receiver depth—on land, thedepth of the hole containing the explosivesource (receivers are usually on the surface),and at sea, how far below the surface thesources and receivers are towed. Thesource-receiver geometry may produceshort-path multiples between the sources,receivers, and the earth or sea surface. If thepath of the multiple is short enough, themultiple—sometimes called a ghost—willclosely trail the direct signal, affecting thesignal’s frequency content. The two-waytravel time of the ghost is associated with afrequency, called the ghost notch, at whichsignals cancel out. This leaves the seismicrecord virtually devoid of signal amplitudeat the notch frequency. The shorter the dis-tance between the source or receiver andthe reflector generating the multiple, thehigher the notch frequency. It is important tochoose a source and receiver depth thatplaces the notch outside the desired band-width. It would seem desirable to plan asurvey with the shallowest possible sourcesand receivers, but this is not always optimal,especially for deep targets. On land, short-path multiples can reflect off near-surfacelayers, making deeper sources preferable. Inmarine surveys, waves add noise and insta-bility, necessitating deeper placement ofboth sources and receivers. In both cases,survey design helps reach a compromise.

The third requirement for good seismicdata is adequate subsurface coverage. Thelateral distance between CMPs at the targetis the bin length (for computation of binlength, see ”Guidelines from Geophysics,”previous page). Assuming a smooth hori-zontal reflector, the minimum source spac-ing and receiver spacing on the surfacemust be twice the CMP spacing at the tar-get. If the reflector dips, reflection points arenot CMPs (above, right). Reflected wavesmay be spatially aliased if the receiver spac-ing is incorrect. A survey designed with goodspatial coverage but assuming flat layersmight fail in complex structure. To recordreflections from a dipping layer involvesmore distant sources and receivers thanreflections from a flat layer, requiring expan-

sion of the survey area—called migrationaperture—to obtain full fold over the target.

In general, survey planners use simpletrigonometric formulas to estimate optimalCMP spacing and maximum source-receiveroffset on dipping targets. As geophysicistsseek more information from seismic data,making the technique more cost-effective,simple rules of thumb will no longer pro-vide optimum results. Forward modeling ofseismic raypaths, sometimes called raytracemodeling, provides a better estimate of sub-surface coverage, but is not done routinelyduring survey planning because of cost andtime constraints. An exception is a recentevaluation by Geco-Prakla for a survey inthe Ship Shoal South Addition area of theGulf of Mexico (page 31).

Balancing Geophysics with Other ConstraintsAcquiring good seismic signal is expensive.On land or at sea, hardware and labor costsconstrain the survey size and acquisitiontime. The job of the survey planner is to bal-ance geophysics and economy, achievingthe best possible signal at the lowest possi-ble cost.8 On land, source lines can bealigned with receiver lines, or they can be atangles to each other. Different source-receiver patterns have different cost and sig-nal advantages, and the planner must

Theoretical Grid

Final Grid

Random Technique

SourceReceiver

Source lineReceiver line

Checkerboard Pattern

Brick Pattern

Zigzag Pattern

ReceiverSource

nCommon source-receiver layouts for landacquisition. The checkerboard pattern(top), sometimes called the straight-line orcross-array pattern, is preferred when thesource is a vibrator truck, because itrequires the least maneuvering. The brickpattern, (middle) sometimes called stag-gered-line, can provide better coverage atshort offsets than the checkerboard, but ismore time-consuming, and so costlier. Thezigzag pattern (bottom) is highly efficient inareas of excellent access, such as deserts,where vibrator trucks can zigzag betweenreceiver lines.

nPlanned versus actual surveys. A survey planned in West Texas,USA (top, left) calls for a checkerboard of receiver lines (blue) andsource lines (red). The actual survey shot (bottom, left) came veryclose to plan. Other cities present acquisition challenges. A surveyin Milan,iItaly (right) used a random arrangement of sources andreceivers. (Adapted from Bertelli et al, reference 9.)

24 Oilfield Review

choose the one that best suits the survey(right). Once a survey pattern is selected,subsurface coverage can be computed interms of fold and distribution of offset andazimuth. If the coverage has systematicholes, the pattern must be modified.iIn com-plex terrain, planned and actual surveysmay differ significantly (left).9

Land acquisition hardware can cost $5million to $10 million for recording equip-ment and sources—usually vibrating trucksor dynamite—but labor is the major surveycost. Cost can be controlled by limiting thenumber of vibrator points or shotpoints, orthe number of receivers. But limitingreceivers limits the area that can be shot atone time. If a greater area is required,receivers must be picked up and moved,increasing labor costs. The most efficientsurveys balance source and receiverrequirements so that most of the time isspent recording seismic data and not wait-ing for equipment to be moved. Land prepa-ration, such as surveying source andreceiver locations and cutting paths throughvegetation or topography, must be includedon the cost side of the planning equation. Incountries where mineral rights and land sur-

face rights are separately and privately held,such as in the US, landowners must givepermission and can charge an access fee.Other constraints that can affect surveyplanning include hunting seasons, per-mafrost, population centers, breeding sea-sons, animals migrating or chewing cables,and crops that limit vibrator source trucks tofarm roads.

Marine survey planners consider differentconstraints. Hardware is a major cost;sources and recording equipment are a siz-able expense, but additionally, seismic ves-sels cost $35 to $40 million to build, and

25April 1994

nMarine acquisi-tion geometryshowing seismicvessels looping inoblong circuits. The length ofstraight segments iscalculated fromfold plots, and mustinclude additionallength—“run in”and “run out”—toallow cable tostraighten aftereach turn.

9. Bertelli L, Mascarin B and Salvador L: “Planning andField Techniques for 3D Land Acquisition in HighlyTilled and Populated Areas—Today’s Results andFuture Trends,” First Break 11, no. 1 (January 1993):23-32.

10. Hird GA, Karwatowski J, Jenkerson MR and Eyres A:“3D Concentric Circle Survey—The Art of Going inCircles,” EAEG 55th Meeting and Technical Exhibi-tion, Stavanger, Norway, June 7-11, 1993.

11. Gausland I: “Impact of Offshore Seismic on MarineLife,” EAEG 55th Meeting and Technical Exhibition,Stavanger, Norway, June 7-11, 1993.

12. Petersen C, Brakensiek H and Papaterpos M:“Mixed-Terrain 3D Seismics in the Netherlands,”Oilfield Review 4, no. 3 (July 1992): 33-44.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaBin

tens of thousands of dollars per day to oper-ate. Sources are clusters of air guns of differ-ent volumes and receivers are hydrophonesstrung 0.5 m [1.6 ft] apart in groups of up to48, on cables up to 6000 m [19,680 ft]long. Sources and receivers are almostalways towed in straight lines across the tar-get (below, right), although other geometriesare possible. Circular surveys have beenacquired with sources and receivers towedby vessels running in spirals or concentriccircles.10 Geco-Prakla’s QUAD-QUAD sys-tem tows four receiver cables and foursource arrays simultaneously, acquiring 16lines at a time. Currents and tides can causethe long receiver cables to deviate by calcu-lable amounts—up to 30°—from the towingdirection. Spacing between shotpoints is afunction of vessel speed, and can be limitedby how quickly the air guns can recover fullpressure and fire again. Access is usuallylimited only by water depth, but drillingrigs, production platforms and shippinglanes can present navigational obstacles.Environmental constraints also influencemarine surveys: the commercial fishingindustry is imposing limits on location of,and seasons for, marine acquisition.11 Forexample, planning in the Caspian Sea mustavoid the sturgeon breeding season or seis-mic surveys would wipe out caviar produc-tion for the year.

Transition zones—shallow water areas—have their own problems, and require spe-cialized equipment and creative planning.12

Transition zones are complex, involvingshorelines, river mouths, coral reefs andswamps. They present a sensitive environ-ment and are influenced by ship traffic,commercial fishing and bottom obstruc-tions. Survey planners have to contend withvarying water depths, high environmentalnoise, complex geology, wind, surf andmultiple receiver types—often a combina-tion of hydrophones and geophones.

One thing all surveys have in common isthat planning must be done quickly. The

clock starts ticking once acreage is licensed.Exploration and development contractsrequire oil companies to drill a certainnumber of wells, spend a certain amount ofmoney, or shoot a certain amount of seis-mic data before a given date. There is oftenlittle time between gaining approval toexplore or develop an area and having todrill. In some cases, oil companies planevery detail of the acquisition before puttingthe job out to bid. In other cases, toincrease efficiency, oil companies and seis-mic service companies share the planning.In many cases, service companies plan thesurvey from beginning to end based onwhat the oil company wishes to achieve. Inthe quest for cost savings, however, seismicsignal is often compromised.

Cost-Effective Seismic PlanningHow would 3D seismic acquisition, pro-cessing and interpretation be different if alittle more emphasis were given to surveydesign? Geco-Prakla’s Survey Evaluationand Design team in Gatwick, England, hasshown that by taking a bit more care, signalcan be improved, quality assured and costoptimized simultaneously. There are threeparts to the process as practiced by Geco-Prakla—specification, evaluation and design(next page). Specification defines the surveyobjectives in terms of a particular depth ortarget formation, and the level of interpreta-tion and resolution required. The level ofinterpretation must be defined early; data tobe used solely for structural interpretationcan be of lesser quality, leading to lower

VS

PLo

gs

or

1D M

od

els

2D o

r 3D

Sur

face

Sei

smic

DataType Process or Output

•Source signature for various depths

•Target wavelet

•Bandwidth at target

•Mute, stack, fold tests

Means toDetermine Parameters

Parameters to be Determined

•Maximum frequencies attainable

•Resolution attainable

•Estimate spatial and temporal resolution

•Establish noise mechanisms

•Near trace offset

•Useful offset with time, stack and S/N relationship

•Reflection response of target

•Identification of multiples origin

•Noise levels

•Shooting direction

•Synthetic shots

•Migration aperture

•Long-offset analysis

•Normal incidence stacks

•Statics model

•Signal-to-noise ratio

•Noise records

•Amplitude versus time plots

•VSP processing

•Source modeling

•Apply losses to source signatures

•Build geological 2D model and apply appropriate target wavelet

•Analysis of 2D synthetic CMP gathers

•Analysis of existing surface seismic

•Analysis of migration requirements

Define surveyobjectives

Specification

Evaluation

NoYesNo Yes

Planning

Resolutionanalysis

Operational,cost and safety

constraints

Resolution, noiseand coverage

analysis

Source,templateand array

design

Objectivesachieved?

Prospectdescription

Requiredequal

obtainable?

Obtainablegeophysicalparameters

Design

Final surveydesign

Analysis ofexisting data

Preferredsurvey

parameters

Requiredgeophysicalparameters

•Loss modeling

•Frequency dependent losses

•Primary/multiple velocity discrimination

•Required streamer length

•Stack fold, offset and group length for optimum multiple moveout discrimination

•Crossline spacing

•Spatial frequency

•Spatial resolution

•Group interval

•Shotpoint interval

•Migration aperture

•Shooting direction

•Record length

•Migration of synthetic zero-offset data

•Migration of existing 2D data

•FK plots, filter tests

•Refraction velocities (near surface)

•Ambient noise estimation

•Source peak amplitude

•Peak-to-bubble ratio

•Source volume

•Source depth

•Modeled section

•Synthetic CMP gathers

26 Oilfield Review

nSurvey evaluation and design scheme.

costs, compared to data used for strati-graphic interpretation, analysis of amplitudevariation with offset (AVO) or seismic moni-toring.13 Specification quantifies the geo-physical parameters needed to meet theinterpretation objectives: frequency contentand signal-to-noise ratio of the recorded sig-nals, and spatial sampling interval—thefamiliar requirements for good signal.

Evaluation of existing data, which can bedone independently and concurrently, tellswhich geophysical parameters are obtain-able—sometimes different from those stipu-lated by specification. The types of dataevaluated include logs, vertical seismic pro-files (VSPs) and 2D or existing 3D data.Existing data can provide models for simu-lating the effects of the geophysical parame-ters on new seismic data. If the requiredparameters are not obtainable, the surveyobjectives are reexamined, or respecified.The loop is repeated until a set of geophysi-cal parameters is found that is both desiredand obtainable.

In the third step, design, the geophysicalparameters are weighed against other con-straints. Keeping in mind the understandinggained from evaluation of existing data, sur-vey planners select the source and receiverconfiguration and choose the shootingsequence and type of seismic source. Thesepreferred survey parameters are tempered bycost, safety and environmental constraints.

nTests with dyna-mite sources at dif-ferent depths.Traces recordedfrom the shot at 28m [92 ft] (left) showless low-frequencynoise—groundroll—than from theshot at 9 m (right).In general, thedeeper the source,the less ground rollgenerated.

nOriginal roll-along geometry proposed for Elf Petroleum Nigeria survey. Four receiverlines would be laid at 300-m intervals. Eachline would have 144 receivers with 50-mspacing. Shots would be fired at 50-m inter-vals in a line perpendicular to the receiverlines, and then the four receiver lines wouldbe rolled along to the next position.

27April 1994

13. For a review of AVO see:Chiburis E, Franck C, Leaney S, McHugo S and Skid-more C: “Hydrocarbon Detection With AVO,” Oil-field Review 5, no. 1 (January 1993): 42-50.For more on seismic monitoring see:Albright J, Cassell B, Dangerfield J, Deflandre J-P,Johnstad S and Withers R: “Seismic Surveillance forMonitoring Reservoir Changes,” Oilfield Review 6,no. 1 (January 1994): 4-14.

14. Source patterns are groups of dynamite charges inseparate holes at the same depth, fired simultane-ously. The goal is to cancel low-frequency noise thattravels laterally, called ground roll.

300 m

ReceiverSource

Tim

e, s

ec

Minimal ground roll

Shot Depth 28 m Shot Depth 9 m

Offset

Ground roll

4.0

3.0

2.0

1.0

0

Offset

Putting Planning into PracticeIn 1991 Elf Petroleum Nigeria Limited putout for tender a 160-km2 [62-sq mile] landsurvey in the Niger Delta. Working with theSeismic Acquisition Service of Elf AquitaineProduction in Pau, France, the Survey Eval-uation and Design group evaluated sourcesand geometries for optimal acquisition. Theprimary target is the structure of the Ibewaoilfield at 3500 m [11,480 ft], at or below 3sec two-way time, with secondary deeperobjectives. Signal-to-noise requirements,based on previous experience, suggestedthe data should be 24-fold. Resolution ofthe target required signal bandwidth of 10 to60 Hz and 25 m by 25 m [82 ft by 82 ft]bins. The source was specified to be dyna-mite, which would be fired in shotholesdrilled and cased or lined to 25 m, againbased on previous experience. Constraintson the survey included the high populationdensity, potential damage to personal prop-erty and the many oil pipelines that crossthe area. A roll-along acquisition patternsimilar to a checkerboard was suggested inthe bid, with four receiver lines to be movedas the survey progressed (below, right).

Evaluation of existing data—2D seismiclines and results from seismic sourcetests—warned of potential problem areas.Source tests compared single-source dyna-mite shots to source patterns, and tested sev-eral source depths.14 The tests indicated thepresence of ghost notches at certain depths,leading to a reduction in signal energywithin the desired frequency band of 10 to60 Hz (above, right). The source tests alsoindicated source patterns were ineffective incontrolling ground roll in this prospect area.Deployment of the source at 9 m [30 ft]gave a good S/N ratio at 25 to 60 Hz, butproduced very high levels of ground roll.Deployment of the source below 40 m [130ft] gave a good S/N ratio from 10 to 60 Hzand low levels of ground roll. However,such deep holes might be unacceptablytime-consuming and costly.

Evaluation of existing 2D lines revealedthe frequency content that could be

nFiltered 2D datashowing frequencycontent variationwith depth. Eachpanel has been fil-tered to allow a dif-ferent band of fre-quencies, called thepassband, to pass.As the passbandrises, the maximumdepth of penetrationof seismic energydecreases. Lower frequencies (left)penetrate deeper.Higher frequencies(right) do not propa-gate to deeper lev-els. At the targetlevel of 3.0 sec thereis still some 50 Hzenergy left.

Tim

e, s

ec

10-20 Hz0-10 Hz 20-30 Hz 30-40 Hz 40-50 Hz

4.0

3.0

2.0

1.0

0

expected from seismic data in the area(above). Resampling along the 2D line atthe sampling interval planned for the 3Dsurvey confirmed that the 50-m [165-ft]receiver and shot spacings initially recom-mended were appropriate. Fold-reductionsimulations performed on the 2D sectionsshowed that 24-fold would be appropriatefor the survey. However, a brick patternwould give better fold and offset distributionthan the roll-along pattern, potentiallyimproving the survey results. The brick pat-tern would also reduce the lateral offsetbetween source and receiver line, thusreducing the potential for ground roll arriv-ing at the same time as the reflection fromthe target and making the ground roll easierto handle in processing.

28

The complete survey evaluation anddesign took two months and reached thefollowing conclusions.1. A target bandwidth of 10 to 60 Hz is a

reasonable acquisition objective.2. Placement of sources deeper than 40 m

would avoid complex processing prob-lems and high levels of ground roll in the3D data set. If logistics prevent locatingthe sources at this depth, then a fallbackdeployment of sources at 9 m wouldmeet the target bandwidth criterion withminimal notching but higher levels ofground roll. Field quality control shouldverify there is no notch between 10 and60 Hz.

3. A 144-trace brick pattern with 300-m[984-ft] receiver line spacing and 300-mshot line spacing would give the best off-set distribution.

4. Shot and receiver intervals should be nomore than 50 m.

Drilling 40-m holes for each source locationwas deemed impractical. Optimizing costsand logistics, the company obtained satis-factory results with a 24-m [79-ft] sourcedepth, single-shot dynamite, and brickworkacquisition pattern.

Evaluation and design can be different inthe marine setting. A case in point is the AlShaheen location in offshore Qatar, underdevelopment appraisal by Maersk Oil QatarAS, according to an agreement with QatarGeneral Petroleum Corporation (QGPC).Maersk Oil had only eight months to design

and acquire a 3D survey that would providea 25 km2 [9.6 sq mile] image, requiringabout 49 km2 [18.8 sq mile] of full fold data,and to spud a vertical developmentappraisal well. Given the tight schedule—processing alone normally takes a year—Maersk Oil contracted a survey evaluationand design study based on existing VSPs and2D surveys. This study was more extensivethan the previous example, with more pre-existing data, particularly well data.

The objective of the 3D survey was toproduce a stratigraphic image of theKharaib limestones and a thin 13- to 15-ft[4- to 4.6-m] thick overlying oil-filled sand.The seismic data were to be analyzed forporosity-related amplitude variations alongwith small-scale faulting and fracturing tohelp in planning the trajectory of future hor-izontal wells. The acquisition vessel hadalready been contracted, limiting the seis-mic source to a 1360- or 1580-in.3 [22,290-or 25,900-cm3] air gun.

Evaluation of existing data indicated areaswhere special care had to be taken toensure a successful survey. For example,high-velocity beds at the seafloor promisedto cause strong multiples, reducing theenergy transmitted to deeper layers and

Oilfield Review

nVertical seismic profile (VSP) traces (left) analyzed for amplitude loss with depth (right).Amplitudes of first arrivals recorded in a 92-level VSP are calibrated with amplitudes of asurface reference signal to account for changes in source amplitude from level to level.The amplitude ratio from one level to the next is plotted in decibels (dB). One dB is 20times the log of the amplitude ratio. An amplitude ratio of 100 is equivalent to 40 dB.

nBandpass filters on VSP data showing energy present up to 80 to 100 Hz at target.Each panel passes a different band of frequencies. Coherent energy up to 80 to100 Hz reflects from the survey objective at 0.8 sec.

Mea

sure

d de

pth,

ft

Leve

l num

ber

Time, sec Amplitude loss from surface, dB

8875

7950

7025

6100

5175

4250

3325

2400

98000 0.5 1.0 80 70 60 50

0

10

20

30

40

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leading to strong reverberations in the waterlayer. A bandwidth of 10 to 90 Hz wasrequired to resolve the thin sands above thetarget and the small faults within it.

Evaluation of existing borehole dataoffered valuable insight into the transmis-sion properties of the earth layers above thetarget and the geophysical parameters thatcould be obtained at the target. Comparisonof formation tops inferred from acousticimpedance logs with reflection depths onthe two VSPs allowed geophysicists to dif-ferentiate real reflections from multiples.Identification of the origin of multiplesallowed the acquisition and processingparameters to be designed to minimize theireffect. Analysis of the amplitude decrease ofthe VSP downgoing first arrivals quantifiedtransmission losses (right). Bandwidth stud-ies on the VSPs showed that frequencies inthe 80- to 100-Hz range were present andbeing reflected at the depth of the target(above). This meant the frequencies requiredfor thin-bed resolution might be obtainableby the 3D survey.

The study also looked into quantifying theseismic resolution of small-scale faulting(next page, top) and analyzed five different

Amplitudes expected from a surface seismic survey would normally be 3 dB less thanthose from a VSP, and scaled by a reflection coefficient.

29April 1994

nResolution of thin beds and small-scale faulting. Each panel shows the modeledresponse of a seismic wave of 48-m [160-ft] wavelength (λ) to a different vertical fault dis-placing a series of thin beds of thicknesses 12 m, 24 m and 36 m. From left to right, faultswith 3-m [10-ft], 6-m [20-ft], 12-m [40-ft] and 24-m [80-ft] throws correspond to λ/16, λ/8,λ/4 and λ/2, respectively. A fault throw of at least 12 m, corresponding to λ/4, can beresolved quantitatively. At less than that, existence of a fault can be detected, but itsthrow resolved only qualitatively.

nA time slice fromMaersk Oil Qatar3D cube showingfractures and faults.

30

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energy sources, source and streamer depth,spatial sampling and minimum and maxi-mum offsets. Some of the early 2D lineswere reprocessed to evaluate migrationrequirements and techniques for removingmultiples.15 Five recommendations wereoffered for survey acquisition:1. A target frequency of 90 Hz is a reason-

able objective and can achieve thedesired resolution.

2. Multiples reverberating in the water willcreate severe problems. Offsets longerthan about 1000 m [3280 ft] may not beuseable because they will contain multi-ples indistinguishable from the targetsignal.

3. Of the available sources, the 1580-in.3source would be preferred to the 1360-in.3 source because of its higher energyoutput at the important higher frequen-cies. This, however, is subject to theability of the larger source to be cycledat a 12.5-m [41-ft] shotpoint interval.

4. Receiver intervals of 12.5 m and shot-point intervals of 12.5 m should suffi-ciently sample the signal and theexpected noise, allowing further reduc-tion of noise during processing. Theseintervals provide sufficient fold toachieve the desired S/N within the 10- to90-Hz bandwidth.

5. Because the primary reflection and multi-ples cannot be discriminated by differ-ences in their velocities, stacking maynot adequately attenuate multiples.Additional demultiple processing maybe necessary.

All the survey design recommendationswere implemented except the larger source,which for technical reasons could not betowed as planned.

The survey acquired superb data. MaerskOil Qatar drilled the vertical well on timeand based on interpretation of the new seis-mic data, spudded two horizontal wells—one with a 10,200-ft [3120-m] long horizon-tal section. The 3D data show fine-scalefaulting and two fracture sets (left ). Faultlocation prediction based on interpretationof the 3D data was confirmed during

Oilfield Review

nRaytrace modeling showing strong changes in reflection paths through salt. Traces thatwould have a common midpoint in a flat-layered earth no longer bounce in the samebin. Salt, with its ability to deform and its high seismic velocity, creates complex structureand strong refraction, or ray bending.

nShip Shoal South Addition in the Gulf ofMexico.

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drilling. Faults with throws as little as 8 to 10ft [2.5 to 3 m] interpreted in the seismic datawere verified by on-site biostratigraphicevaluation of the reservoir limestones.

In addition to these two surveys, Geco-Prakla has conducted more than 30 othersurvey evaluation and design studies, some-times with surprising results. In one case,analysis of tidal currents led the team to pro-pose a change of 120° in shooting direction,which would add $150,000 to the process-ing cost, but cut 45 days and $1,500,000 offthe acquisition cost, for a savings of $1.35million. In another study, analysis of previ-ous seismic data showed that coherent shot-generated noise was aliased at shot intervalsof 37.5 m [123 ft]. Although it wouldincrease acquisition and processing costs, adenser shot interval of 25 m would samplethe noise sufficiently to allow removal dur-ing processing. The 37.5-m shot spacingwas used in the survey, giving data thatrequired extra prestack processing costs,which did not entirely eradicate the noise.

In a study with Schlumberger TechnicalServices in Dubai, UAE, data from a VSPacquired just before a marine 3D surveyhelped optimize planning.16 In a deviatedproduction well near the center of the sur-vey, a slimhole TWST Through-Tubing WellSeismic Tool was run through tubing to thereservoir to record shots fired from the seis-mic source to be used in the 3D survey. Theshot records allowed geophysicists to deter-mine the effects at the depth of the target ofsource parameters such as air-gun volume,depth and pressure. The records alsoshowed that at far offsets, high amplitudeshear waves contaminate the traces. With ashorter receiver cable, a better survey wasacquired in less time, and so for lower cost,than originally planned.

April 1994

For the FutureSome of the advances to be made in 3D sur-vey design have origins in other fields. VSPdesign routinely models seismic raypathsthrough complex subsurface structure, butrarely does surface seismic design accountfor structure. Despite considerable sophisti-cation in 3D data processing, most 3D sur-vey design assumes plane layer geometry inthe subsurface to calculate midpoints andtarget coverage. But to estimate subsurfacecoverage adequately in complicated struc-

15. Migration, sometimes called imaging, is a processingstep that rearranges recorded seismic energy back tothe position from which it was reflected, producingan image of the reflector.

16. Poster C: “Taking the Pulse of 3D Seismics,” MiddleEast Well Evaluation Review, no. 13 (1992): 6-9.

ture, survey designers recognize the need tomodel raypaths, and some are beginning todo this. Geco-Prakla has used raytracemodeling to determine coverage in a surveyto image below salt in the Ship Shoal SouthAddition in the Gulf of Mexico (left).

Salt introduces large contrasts in seismicvelocity, bending and distorting seismic raysalong complex paths (top). Survey designersanticipated that a super-long receiver cablewould be required to provide adequate cov-erage of the subsalt layers. They tested vari-ous cable lengths by shooting raypathsthrough a geologic model derived from 2D

31

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nRaytrace modeling to optimize cable length. Refraction through salt may mean a longercable is required to image structure below. Two cable lengths, 8075 m (top) and 5425 m(bottom) were tested using the model on the previous page. Surprisingly, in this case bothcables give similar coverage of subsalt horizons.

seismic data (above). Surprisingly, a stan-dard 5425-m [17,794-ft] cable providescoverage similar to that of the proposed8075-m [26,500-ft] cable.

Another advance may come through inte-gration of survey design with acquisition,processing and interpretation into a singlequality-assured operation. The aim is tomaximize cost-effectiveness of the overallseismic survey, to supply quality-assuredprocessed data with minimum turnaroundtime and optimal cost. Within Geco-Prakla,this idea is called Total Quality 3D, orTQ3D. Such surveys may be acquired on aproprietary (exclusive) or a speculative(nonexclusive) basis, or a combination ofthe two. For example, 75% of a 700-km2

[271-sq mile] TQ3D survey in the southernUK continental shelf will be delivered as

32

proprietary data to three oil companies. Theremaining 25% is nonexclusive, andalthough sponsored in part by the currentplayers in this area, the data will also beavailable to new players.

Defining the objectives of a TQ3D surveycan be a difficult process. Rather than haz-arding a guess at which reflectors in an areaare the sought-after targets, Geco-Praklaplanners involve proprietary and nonexclu-sive clients at early stages of the project.Over open acreage they examine a database of nonexclusive 2D seismic surveys tolearn about the targets.

Choosing acquisition parameters that willbe optimal over the entire survey is also achallenge. It is not always practical to followall the recommendations proposed by a sur-vey evaluation and design study, but a judg-ment can be made of the impact that anydecision will have on the quality of the data.Then, other options can be explored. For

example, in a recent TQ3D survey, steeplydipping reflectors in 20% of the area wouldhave been optimally sampled if the receiverspacing had been reduced from 25 m to 20m [66 ft], but the 25% additional cost wasunacceptable to clients. Having flagged thisas an area where data quality could beimproved, attention will be paid to process-ing that may help imaging of steep dips.

As oil companies and service companiesstrive for efficiency and acquisition of high-quality, cost-effective seismic data, moreemphasis is being placed on survey design.The other pieces of the seismic puzzle—acquisition, processing and interpreta-tion—have all benefited from advances intechnology, and survey design is followingthe trend. Through powerful modeling andintegration of log, VSP and surface seismicdata, 3D survey design will become thefoundation for all that follows. —LS

Oilfield Review

Designing and Managing Drilling Fluid

Gone are the days when drilling fluid—or mud as it is commonly called—comprised only clay and water.

Today, the drilling engineer designing a mud program chooses from a comprehensive catalog of ingredients.

The aim is to select an environmentally acceptable fluid that suits the well and the formation being drilled, to

understand the mud’s limitations, and then to manage operations efficiently within those limitations.

April 1994

Ben BloysARCO Exploration and Production TechnologyPlano, Texas, USA

Neal DavisChevron Petroleum Technology CompanyHouston, Texas, USA

Brad SmolenBP Exploration Inc.Houston, Texas, USA

Louise BaileyOtto HouwenPaul ReidJohn SherwoodCambridge, England

Lindsay FraserHouston, Texas, USA

Mike HodderMontrouge, France

There are good reasons to improve drillingfluid performance and management, notleast of which is economics. Mud may rep-resents 5% to 15% of drilling costs but maycause 100% of drilling problems. Drillingfluids play sophisticated roles in the drillingprocess: stabilizing the wellbore withoutdamaging the formation, keeping formationfluids at bay, clearing cuttings from the bitface, and lubricating the bit and drillstring,to name a few.1 High-angle wells, high tem-peratures and long, horizontal sectionsthrough pay zones make even more rigor-ous demands on drilling fluids.

Furthermore, increasing environmentalconcerns have limited the use of some ofthe most effective drilling fluids and addi-tives.2 At the same time, as part of the indus-try’s drive for improved cost-effectiveness,drilling fluid performance has come underever closer scrutiny.

This article looks at the factors influencingfluid choice, detailing two new types ofmud. Then it will discuss fluid managementduring drilling.

In this article MSM (Mud Solids Monitor) and FMP (FluidMonitoring Package) are marks of Schlumberger. Fann 35 is a mark of Baroid Corporation.For help in preparation of this article, thanks to JohnAstleford, Schlumberger Dowell, Bottesford, England;Thom Geehan, Schlumberger Dowell, Houston, Texas,USA, Alan McKee and Doug Oakley, SchlumbergerDowell, St. Austell, England; Eric Puskar, SchlumbergerDowell, Clamart, France.1. For a comprehensive review of the role of drilling

fluids:Darley HCH and Gray GR: Composition and Proper-ties of Drilling and Completion Fluids, 5th ed. Hous-ton, Texas, USA: Gulf Publishing Co.,1988.

What Influences the Choice of Fluid?Among the many factors to consider whenchoosing a drilling fluid are the well’sdesign, anticipated formation pressures androck mechanics, formation chemistry, theneed to limit damage to the producing for-mation, temperature, environmental regula-tions, logistics, and economics (see “CriticalDecisions,” next page).

To meet these design factors, drilling flu-ids offer a complex array of interrelatedproperties. Five basic properties are usuallydefined by the well program and monitoredduring drilling: rheology, density, fluid loss,solids content and chemical properties (see“Basic Mud Properties and Ingredients,”page 36).3

For any type of drilling fluid, all five prop-erties may, to some extent, be manipulatedusing additives. However, the resultingchemical properties of a fluid dependlargely on the type of mud chosen. And thischoice rests on the type of well, the natureof the formations to be drilled and the envi-ronmental circumstances of the well.

33

2. Geehan T, Helland B, Thorbjørnsen K, Maddin C,McIntire B, Shepherd B and Page W: “Reducing theOilfield’s Environmental Footprint,” Oilfield Review 2,no. 4 (October 1990): 53-63.Minton RC, McKelvie DS, Caudle DD, Ayres RC Jr.,Smith JP, Cline JT, Duff A, Blanchard JR and Read AD:“The Physical and Biological Impact of Processed OilDrill Cuttings: E&P Forum Joint Study,” paper SPE26750, presented at the Offshore Europe Conference,Aberdeen, Scotland, September 7-10, 1993.

3. For a full description of these properties and theirmeasurement:Geehan T and McKee A: “Drilling Mud: Monitoringand Managing It,” Oilfield Review 1, no. 2 (July1989): 41-52.

Critical Decisions

• Temperature

High-temperature well More than 275-300°F may cause product degradation

•Fois

• Formation pressure and strength information

Pore pressure Determines minimum mud weight needed to prevent blowout

Rock strength-fracture Indicates maximum gradient mud weight that will not

fracture well

Issue Decision

34

• Logistics

Remote location well May prevent the use of systems that consume large quantities of chemicals

• Geology

Composition and Determines mud arrangement of the chemistry/compositionminerals in the formation and the clay chemistry

• Well design data

Well profile/angle Indicates the rheology needed to optimize hole cleaning. High-angle wells may need enhanced lubricity •

Diameter of casing •Determines the velocityrequired for hole cleaning and pumpingand solids controlhardware needed

Strength and stress Potential wellbore states versus hole angle stability issues may

concern mud weight

Length of exposed Greater inhibition open hole. needed for longer

sections •

• Environmental and health considerations

Specific health and Determines mud system environmental concerns cuttings treatment/ on type of mud and disposal strategydisposal of cuttings

Shales are the most common rock typesencountered while drilling for oil and gasand give rise to more problems per meterdrilled than any other type of formation.Estimates of worldwide, nonproductivecosts associated with shale problems are putat $500 to $600 million annually.4 Commondrilling problems like stuck pipe arise fromhole closure and collapse, erosion and poormud condition. In addition, the inferiorwellbore quality often encountered in shalesmay make logging and completion opera-tions difficult or impossible.

Shale instability is largely driven bychanges in stress and chemical alterationcaused by the infiltration of mud filtratecontaining water (next page, top).5 Over theyears, ways have been sought to limit inter-action between mud filtrate and water-sensi-tive formations. So, for example, in the late1960s, studies of mud-shale reactionsresulted in the introduction of a water-basemud (WBM) that combines potassium chlo-ride [KCl] with a polymer called partially-hydrolyzed polyacrylamide—KCl-PHPAmud.6 PHPA helps stabilize shale by coatingit with a protective layer of polymer—therole of KCl will be discussed later.

The introduction of KCl-PHPA mudreduced the frequency and severity of shaleinstability problems so that deviated wells inhighly water-reactive formations could be

Formation damage constraints

rmation being drilled Requires nondamaging pay zone mud to limit

invasion, wettability effects of mud, potential emulsionblockage of the formation, fines mobilization and invasion, scale formation.

4. Boll GM, Wong S-W, Davidson CJ and Woodland DC:“Borehole Stability in Shales,” paper SPE 24975, pre-sented at the SPE European Petroleum Conference,Cannes, France, November 16-18, 1992.

5. Allen D, Auzerais F, Dussan E, Goode P, RamakrishnanTS, Schwartz L, Wilkinson D, Fordham E, Hammond Pand Williams R: “Invasion Revisited,” Oilfield Review3, no. 3 (July 1991): 10-23.

6. Bailey L, Reid PI and Sherwood JD: “Mechanisms andSolutions for Chemical Inhibition of Shale Swelling andFailure,” presented at the Royal Society of Chemistry5th International Symposium, Chemistry in the OilIndustry, Ambleside, Cumbria, UK, April 12-14, 1994.Steiger RP: “Fundamentals and Use of Potassium/Poly-mer Drilling Fluids to Minimize Drilling and Comple-tion Problems Associated With Hydratable Clays,”Journal of Petroleum Technology 34 (August 1982):1661-1670.O’Brien DE and Chenevert ME: “Stabilizing SensitiveShales With Inhibited, Potassium-Based Drilling Flu-ids,” paper SPE 4232, Journal of Petroleum Technology25 (1973): 1089.

7. Chemical potential can be though of as an increase inthe internal energy of the system when one mole ofsubstance is added to an infinitely large quantity of themixture so as not to change its overall composition.For more information about thermodynamic potentials:Fletcher P: Chemical Thermodynamics for Earth Scien-tists. Harlow, Essex, England: Longman Scientific &Technical, 1993.

8. Mody FK and Hale AH: “A Borehole Stability Model toCouple Mechanics and Chemistry of Drilling FluidShale Interactions,” paper SPE 25728, presented at theIADC/SPE Drilling Conference, Amsterdam, TheNetherlands, February 23-25, 1993.Chenevert ME: “Shale Control With Balanced ActivityOil-Continuous Muds,” Journal of Petroleum Technol-ogy 22 (1970): 1309-1319.

Water migration Base oil

SurfactantFormation (low salinity water)

Water and salts (high salinity)

nShale instability. In this example, Pierre shale has been exposed to a mud comprisingfresh water and bentonite gel. Because this fluid contains no inhibitors, water hasentered the shale causing it to swell and weakening the formation. Continuous flow ofmud has eroded the borehole leaving an enlarged hole that would be hard to log andcomplete. This simulation was carried out using the small wellbore simulator at Schlum-berger Cambridge Research, Cambridge, England.

nHow oil-base mud’s semipermeable mem-brane works. OBM comprises droplets ofaqueous fluid surrounded by oil. A layer ofsurfactant on the surface of each waterdroplet acts like a semipermeable mem-brane, separating the aqueous solution inthe mud from the formation and its water.Water passes through this membrane fromthe solution with the lowest concentrationof salt to the one with the highest.

drilled, although often still at a high costand with considerable difficulty. Since then,there have been numerous variations on thistheme as well as other types of WBM aimedat inhibiting shale.

However, in the 1970s, the industryturned increasingly towards oil-base mud(OBM) as a means of controlling reactiveshale. Today, OBM not only provides excel-lent wellbore stability but also good lubrica-tion, temperature stability, a reduced risk ofdifferential sticking and low formation dam-age potential. OBM has been invaluable inthe economic development of many oil andgas reserves.

The use of OBM would probably havecontinued to expand through the late 1980sand into the 1990s but for the realizationthat, even with low-toxicity mineral base-oil, the disposal of OBM cuttings can have alasting environmental impact. In many areasthis awareness led to legislation prohibitingor limiting the discharge of these wastes.This, in turn, has stimulated intense activityto find environmentally acceptable alterna-tives and has boosted WBM research.

To develop alternative nontoxic muds thatmatch the performance of OBM requires anunderstanding of the reactions that occurbetween complex, often poorly character-ized mud systems and equally complex,highly variable shale formations.

Requisites for a Successful Drilling FluidMost OBM is an invert emulsion comprisingdroplets of aqueous fluid surrounded by oil,which forms the continuous phase. A layerof surfactant on the surface of the waterdroplet acts like a semipermeable mem-brane, separating the aqueous solution inthe mud from the formation and its water.Water will pass through this membrane fromthe solution with the lowest concentrationof a salt to the one with the highest—osmo-sis (right).

A key method of maintaining shale stabil-ity using OBM is to ensure that the ionicconcentration of the salts in the aqueous—internal—phase of the mud is sufficientlyhigh, so that the chemical potential of thewater in the mud is equal to or lower thanthat of the formation water in the shale.7When both solutions have the same chemi-cal potential, water will not move, leavingthe shale unchanged. If the water in theinternal phase of the mud has a lowerchemical potential than the fluid in the for-mation, water will travel from the shale tothe mud, drying out the rock. Unless dehy-dration is excessive, this drying out usuallyleaves the wellbore in good condition.8

April 1994

In WBM, there have been many efforts toprotect a water-sensitive formation frommud filtrate. One technique is to introducea buffer in the form of blocking and plaster-ing agents, ranging from starches and cellu-loses, through polyacrylamides to asphaltsand gilsonites. Total control cannot beachieved in this way so specific inhibitingcations—chiefly potassium [K+] and cal-cium [Ca2+] ions—are traditionally addedto the base water to inhibit the clay fromdispersing—to stop it from breaking upwhen attacked by aqueous solution. This is

35

3

Basic Mud Properties and Ingredients

1. For a complete description of the traditional mud checktechniques:

Geehan T and McKee A: “Drilling Mud: Monitoring andManaging It,” Oilfield Review 1, no. 2 (July 1989): 41-52.

2. Plastic viscosity (PV) and yield point (YP) are relatedparameters and follow common oilfield conventionsbased on the Bingham rheological model. PV is largelydependent on the type of mud and its solids content. Thelower the PV, the faster the drilling penetration rate. How-ever, this is limited by the YP, which is a direct measure ofthe fluid’s cuttings-carrying efficiency.

For details of rheology:

Bittleston S and Guillot D: “Mud Removal: ResearchImproves Traditional Cementing Guidelines,” Oilfield

Basic Mud Properties

Five basic properties are usually defined by the

well program and monitored during drilling:1

Rheology—A high viscosity fluid is desirable to

carry cuttings to surface and suspend weighting

agents in the mud (such as barite). However, if

viscosity is too high, friction may impede the cir-

culation of the mud causing excessive pump

pressure, decrease the drilling rate, and hamper

the solids removal equipment. The flow regime

of the mud in the annulus is also affected by vis-

cosity.2 Measurements made on the rig include

funnel viscosity using a Marsh funnel—an orifice

viscometer—and plastic viscosity, yield point

and gel strength using a Fann 35 viscometer or

equivalent.

Density—Sufficient hydrostatic pressure is

required to prevent the borehole wall from caving

in and to keep formation fluid from entering the

wellbore. The higher the density of the mud com-

pared to the density of the cuttings, the easier it

is to clean the hole—the cuttings will be less

inclined to fall through the mud. If the mud

weight is too high, rate of drilling decreases, the

chances of differential sticking and accidentally

fracturing the well increase, and the mud cost

will be higher. The most common weighting

agent employed is barite. Density is measured on

the rig using a mud balance.

Fluid loss—The aim is to create a low-permeabil-

ity filter cake to seal between the wellbore and

the formation. Control of fluid loss restricts the

invasion of the formation by filtrate and

minimizes the thickness of filter cake that builds

up on the borehole wall, reducing formation dam-

age and the chances of differential sticking.

Static fluid loss is measured on the rig using a

standard cell that forces mud through a screen,

and also using a high-temperature, high-pressure

test cell.

Solids content—Solids are usually classified as

high gravity (HGS)—barite and other weighting

agents—or low gravity (LGS)—clays, polymers

and bridging materials deliberately put in the

6

Review 3, no. 2 (April 1991): 44-54.

mud, plus drilled solids from dispersed cuttings

and ground rock. The amount and type of solids in

the mud affect a number of mud properties. A high

solids content, particularly LGS, will increase

plastic viscosity and gel strength. High-solids

muds have much thicker filter cakes and slower

drilling rates. Large particles of sand in the mud

cause abrasion on pump parts, tubulars, measure-

ment-while-drilling equipment and downhole

motors. Measurement of total solids is tradition-

ally carried out using a retort—which distils off the

liquid allowing it to be measured, leaving the

residual solids.

Chemical properties—The chemical properties of

the drilling fluid are central to performance and

hole stability. Properties that must be anticipated

include the dispersion of formation clays or disso-

lution of salt formations; the performance of other

mud products—for example, polymers are

affected by pH and calcium; and corrosion in the

well (see “Corrosion in the Oil Industry,” page 4).

Measurement rigside usually relies on simple

chemical analysis to determine pH, Ca2+, total

hardness, concentrations of Cl- and sometimes K+.

Mud Ingredients

Water—In water-base mud (WBM) this is the

largest component. It may be used in its natural

state, or salts may be added to change filtrate

reactivity with the formation. Water hardness is

usually eliminated through treatment and alkalin-

ity is often controlled.

Weighting agents—These are added to control for-

mation fluid pressure. The most common is barite.

Clay—Most commonly, bentonite is used to pro-

vide viscosity and create a filter cake on the bore-

hole wall to control fluid loss. Clay is frequently

replaced by organic colloids such as biopolymers,

cellulose polymers or starch.

Polymers—These are used to reduce filtration,

stabilize clays, flocculate drilled solids and

increase cuttings-carrying capacity. Cellulosic,

polyacrylic and natural gum polymers are used in

low-solids mud to help maintain hole stability and

minimize dispersion of the drill cuttings. Long-

chain polymers are adsorbed onto the cuttings,

thereby preventing disintegration and dispersion.

Thinners—These are added to the mud to reduce

its resistance to flow and to stifle gel develop-

ment. They are typically plant tannins, polyphos-

phates, lignitic materials, lignosulfonates or syn-

thetic polymers.

Surfactants—These agents serve as emulsifiers,

foamers and defoamers, wetting agents, deter-

gents, lubricators and corrosion inhibitors.

Inorganic chemicals—A wide variety of inorganic

chemicals is added to mud to carry out various

functions. For example, calcium hydroxide is

used in lime mud and calcium chloride in OBM;

sodium hydroxide and potassium hydroxide

(caustic soda and caustic potash) are used to

increase mud pH and solubilize lignite; sodium

carbonate (soda ash) to remove hardness, sodium

chloride for inhibition and sodium chloride has

many uses—such as increasing salinity, increas-

ing density, preventing hydrate formation and pro-

viding inhibition.

Bridging materials—Calcium carbonate, cellulose

fibers, asphalts and gilsonites are added to build

up a filter cake on the fractured borehole and help

prevent filtrate loss.

Lost circulation materials—These are used to

block large openings in the wellbore. These

include walnut shells, mica and mud pills con-

taining high concentrations of xanthum and modi-

fied cellulose.

Specialized chemicals—Scavengers of oxygen,

carbon dioxide or hydrogen sulfide are sometimes

required, as are biocides and corrosion inhibitors.

Oilfield Review

9. Hale AH and Mody FK: “Partially Hydrolyzed Poly-acrylamide (PHPA) Mud Systems for Gulf of MexicoDeepwater Prospects,” paper SPE 25180, presentedat the SPE International Symposium on OilfieldChemistry, New Orleans, Louisiana, USA, March 2-5, 1993.Bol GM, “The Effect of Various Polymers and Saltson Borehole and Cutting Stability in Water-BaseShale Drilling Fluids,” paper SPE 14802, presentedat the SPE/IADC Drilling Conference, Dallas, Texas,USA, February 10-12, 1986.

10. Sherwood JD and Bailey L: “Swelling of ShaleAround a Cylindrical Wellbore,” Proceedings of theRoyal Society 444, London, England (1994): 161-184.Hale AH, Mody FK and Salisbury DP: “ExperimentalInvestigation of the Influence of Chemical Potentialon Wellbore Stability,” paper SPE 23885, presentedat the SPE/IADC Drilling Conference, New Orleans,Louisiana, USA, February 18-21, 1992.

11. See Bailey et al, reference 6.

12. For details of how mud weight affects mechanicalstability:Addis T, Last N, Boulter D, Roca-Ramisa L andPlumb D: “The Quest For Borehole Stability in theCusiana Field, Colombia,” Oilfield Review 5, no.2/3 (April/July 1993): 33-43.Steiger RP and Leung PK: “Predictions of WellboreStability in Shale Formations at Great Depth,” MauryV and Fourmaintraux D (eds): Rock at Great Depth.Rotterdam, The Netherlands: A.A. Balkema (1990):1209-1218.

13. Reid PI, Elliott GP, Minton RC, Chambers BD andBurt DA: “Reduced Environmental Impact andImproved Drilling Performance With Water-BasedMuds Containing Glycols,” paper SPE 25989, pre-sented at the SPE/EPA Exploration and ProductionEnvironmental Conference, San Antonio, Texas,USA, March 7-10, 1993.Downs JC, van Oort E, Redman DI, Ripley D andRothmann B: “TAME: A New Concept in Water-Based Drilling Fluids for Shales,” paper SPE 26999,presented at the Offshore Europe Conference,Aberdeen, Scotland, September 7-10, 1993.

37April 1994

nImproving inhibition with addition of polyglycol. This chart shows the recovery of cut-tings comprising Tertiary shale—London Clay that contains about 20% smectite—thathave been exposed to different muds in an aggressive dispersion test. This test is anindication of a mud’s shale stabilizing qualities rather than a simulation of downholeconditions. The weight of the cuttings before treatment is compared to the weight after-wards. Recovery increased from about 40% to 80% with the addition of polyglycol to aKCl-PHPA mud. Conventional seawater-polymer mud yields about 10%, while OBMshowed almost 100% recovery.

KCL @ 25 lbm/bblPHPA @ 0.75 lbm/bbl

KCI/PHPA

20

0

Seawater/polymer mud

Sha

le re

cove

ry, w

t%

3% Polyol additive

40

60

80

100

OBM

achieved by providing cation exchange withthe clays in the shale—the K+ or Ca2+ com-monly replace the sodium ion [Na+] associ-ated with the clay in the shale, creating amore stable rock that is better able to resisthydration. Hence KCl-PHPA fluids.9

The movement of WBM filtrate from thewellbore into the surrounding shale is con-trolled by the difference between the chemi-cal potentials of the various species in themud, and the corresponding chemicalpotentials within the formation. Chemicalpotential depends both on the mud’s hydro-static pressure in the wellbore and on itschemical composition.10

To design an effective WBM, it is neces-sary to know the relative importance of muddifferential pressure versus chemical con-centration and composition, and how thisrelates to the type of mud and formation.For example, if the rock is chemically inertto WBM filtrate (as is the case with sand-stone), then invasion is controlled solely bythe differences between the welIbore pres-sure and the pore pressure within the rock.But for shale, opinion varies. Some experi-menters suggest that the shale itself can actas a semipermeable membrane, making thechemical components the key determinant.

Researchers at Schlumberger CambridgeResearch tested Pierre shale and found thatit behaves as an imperfect ion exclusionmembrane and that the role of chemicaldifferences between wellbore fluid andpore fluid is less significant than the differ-ence in pressure between the mud and theformation.11 This result is an oversimplifica-tion since it does not consider what hap-pens after fluid invades the formation rais-ing its pore pressure. However, it doessuggest that mud weight should be kept aslow as well safety and mechanical welIborestability considerations allow.12 These andother results are now being used to designmore effective WBM systems and evaluatethose that are already available (see “Strate-gies for Improving WBM Shale Inhibition,”page 39).

A number of relatively new types of mudsystems have been introduced. For example,one route is to substitute the oil phase inOBM with synthetic chemicals. In this way,the excellent characteristics of OBM may bereproduced with a more rapidly biodegradedcontinuous phase than was available before.

Typical synthetic base chemicals includeesters, ethers, polyalphaolefins, linear olefinsand linear alkyl benzenes. One of the chiefdisadvantages of these systems is that theytend to be relatively expensive compared toconventional OBM. However, such systemscan still be cost-effective options compared

to WBM—particularly where OBM wouldhave been used prior to the introduction ofnew environmental constraints.

The State of the WBM ArtThis article will now concentrate onadvances in WBM technology by looking attwo distinct directions of development: theuse of polyols for shale inhibition and theintroduction of mixed-metal hydroxides toimprove hole cleaning and help reduce for-mation damage.

Polyol muds—Polyol is the generic namefor a wide class of chemicals—includingglycerol, polyglycerol or glycols such aspropylene glycol—that are usually used inconjunction with an encapsulating polymer(PHPA) and an inhibitive brine phase (KCl).13

These materials are nontoxic and pass thecurrent environmental protocols, including

those laid down in Norway, the UK, TheNetherlands, Denmark and the USA.

Glycols in mud were proposed as lubri-cants and shale inhibitors as early as the1960s. But it was not until the late 1980sthat the materials became widely consid-ered. Properly engineered polyol muds arerobust, highly inhibitive and often cost-effective. Compared with other WBM sys-tems, low volumes are typically required.Polyols have a number of different effects,such as lubricating the drillstring, opposingbit balling (where clays adhere to the bit)and improving fluid loss. Today, it is theirshale-inhibiting properties that attract mostattention. For example, tests carried out byBP show that the addition of 3 to 5% by vol-ume of polyglycol to a KCl-PHPA mud dra-matically improves shale stabilization(below). However, a significant gap still

38 Oilfield Review

nComparison of the rheologies of MMH and conventional PHPA mud. For MMH, the relatively high 3-and 6-rpm readings and low 300- and 600-rpm readings result in a flat rheology profile that is quite dif-ferent from that of conventional PHPA mud. With use of a Huxley-Bertram rheometer to measure therheologies at 190°F [88°C] and 2500 psi, the MMH shows a relatively high shear-stress intercept and anearly linear rheologic profile. This contrasts with the downward curve of the PHPA mud. [Adapted fromSparling DP and Williamson D: “Mixed Metal Hydroxide Mud Improves Drilling in Unstable Shales,” Oil & Gas Journal 89(June 10, 1991): 29.]

50

20

40

10

30

00 3 6 100 200 300 600

Fann rheometer speed, rpm

MMHPHPA, Partially hydrolized polyacrylamide

Dia

l rea

ding

Rheology Profile

28

16

24

12

20

00 200 400 600 800 1000

Shear rate, sec–1

MMHPHPA

She

ar s

tres

s

Rheology Profile at 190°F and 2500 psi

4

8

remains between the performance of polyolmuds and that of OBM.

Field experience using polyol muds hasshown improved wellbore stability andyielded cuttings that are harder and drierthan those usually associated with WBM.This hardness reduces breakdown of cut-tings and makes solids control more effi-cient. Therefore, mud dilution rates tend tobe lower with polyol muds compared withother WBM systems (for an explanation ofsolids control and dilution, see mud man-agement, page 39).

As yet, no complete explanation of howpolyols inhibit shale reactivity has beenadvanced, but there are some clues:•Most polyols function best in combination

with a specific inhibitive salt, such aspotassium, rather than nonspecific highsalinity.

•Polyol is not depleted rapidly from themud even when reactive shales aredrilled.

•Many polyols work effectively at concen-trations as low as 3%, which is too low tosignificantly change the water activity ofthe base fluid.

•Polyols that are insoluble in water are sig-nificantly less inhibitive than those thatare fully soluble.

•No direct link exists between the perfor-mance of a polyol as a shale inhibitor andits ability to reduce fluid loss.

Many of these clues eliminate theories thattry to explain how polyols inhibit shales.Perhaps the most likely hypothesis—although so far there is no direct experimen-tal evidence supporting it—is that polyolsact as a structure breaker, disrupting theordering of water on the clay surface thatwould otherwise cause swelling and disper-sion. This mechanism does not require theglycol to be strongly adsorbed onto theshale, which is consistent with the lowdepletion rates seen in the field.

Mixed-metal hydroxide (MMH) mud—MMH mud has a low environmental impactand has been used extensively around theworld in many situations: horizontal andshort-radius wells, unconsolidated ordepleted sandstone, high-temperature,unstable shales, and wells with severe lostcirculation. Its principal benefit is excellenthole-cleaning properties.14

Many new mud systems—includingpolyol muds—are extensions of existing flu-ids, with perhaps a few improved chemicalsadded. However, MMH mud is a completedeparture from existing technology. It isbased on an insoluble, inorganic, crystallinecompound containing two or more metalsin a hydroxide lattice—usually mixed alu-minum/magnesium hydroxide, which isoxygen-deficient. When added to prehy-drated bentonite, the positively charged

39April 1994

Strategies for Improving WBM Shale Inhibition

Researchers at Schlumberger Cambridge Research, Cambridge, England, have proposed a number of

strategies for developing mud formulations with improved shale inhibition.1

14. Fraser L and Enriquez F: “Mixed Metal HydroxideFluids Research Widens Applications,” PetroleumEngineer International 63 (June 1992): 43-45.Fraser LJ and Haydel S: “Mixed Metal HydroxideMud Application in Horizontal Wells—Case StudiesUnder Diverse Drilling Conditions,” presented at the5th International Conference on Horizontal WellTechnology, Houston, Texas, USA, November 9-11,1993.

15. Fraser LJ: “Unique Characteristics of Mixed MetalHydroxide Fluids Provide Gauge Hole in DiverseTypes of Formation,” paper SPE 22379, presented atthe SPE International Meeting on Petroleum Engi-neering, Beijing, China, March 24-27, 1992.Lavoix F and Lewis M: “Mixed Metal HydroxideDrilling Fluid Minimizes Well Bore Washouts,” Oil& Gas Journal 90 (September 28, 1992): 87-90.

1. Bailey L, Reid PI and Sherwood JD: “Mechanisms andSolutions for Chemical Inhibition of Shale Swelling andFailure,” presented at the Royal Society of Chemistry 5thInternational Symposium, Chemistry in the Oil Industry,Ambleside, Cumbria, UK, April 12-14, 1994.

MMH particles interact with the negativelycharged clays forming a strong complex thatbehaves like an elastic solid when at rest.

This gives the fluid its unusual rheology:an exceptionally low plastic viscosity-yieldpoint ratio. Conventional muds with highgel strength usually require high energy toinitiate circulation, generating pressuresurges in the annulus once flow has beenestablished. Although MMH has great gelstrength at rest, the structure is easily bro-ken. So it can be transformed into a low-vis-cosity fluid that does not induce significantfriction losses during circulation and givesgood hole cleaning at low pump rates evenin high-angle wells (previous page ). Yetwithin microseconds of the pumps beingturned off, high gel strength develops, pre-venting solids from settling.

There are some indications that MMHalso provides chemical shale inhibition.

This effect is difficult to demonstrate in thelaboratory, but there is evidence that a staticlayer of mud forms adjacent to the rock faceand helps prevent mechanical damage tothe formation caused by fast-flowing mudand cuttings, controlling washouts.15

MMH is a special fluid sensitive to manytraditional mud additives and some drillingcontaminants. It therefore benefits from thecareful management that is vital for all typesof drilling fluid.

Mud Management—Keeping the Fluidin ShapeSelecting a reliable chemical formulation forthe drilling fluid so that it exhibits therequired properties is one part of the job.Maintaining these properties during drillingis another.

Circulation of drilling fluid may be con-sidered a chemical process with the well-

bore acting as a reactor vessel. In this reac-tor, the composition of the drilling fluid willbe changed dynamically by such factors asfiltration at the wellbore and evaporation atsurface; solids will be added and takenaway by the drilling process and the solids-control equipment; chemicals will be lost as

Preventing Filtrate Access

Creation of a semipermeable membrane—If an

effective membrane can be produced on the sur-

face of the shale by adding suitable surfactants to

WBM, then water ingress could be controlled

using chemical activity as in OBM. This effect

was obtained, to some degree, with the direct-

emulsion WBM used occasionally in the 1980s.

The challenge is to identify effective surface

active molecules that are environmentally

acceptable, do not unduly affect other mud prop-

erties and, ideally, show low depletion rates.

Provision of fluid-loss control—Conventional

fluid-loss control polymers produce mud filter

cakes that are typically one or two orders of mag-

nitude higher in permeability than shales. Even if

fractures are present, such polymers may be

effective at plugging these relatively large holes,

but filter cakes are otherwise unlikely to form on

shale. If they did, the shale—the less permeable

of the two solid phases—would still control the

rate of fluid transport. Given the small dimen-

sions of pores in shales—on the order of

nanometers—fluid loss control is likely to be best

achieved either by chemical reactions that greatly

reduce, or even eliminate, permeability or by

molecules small enough to block pore throats.

Increasing the viscosity of the filtrate—

By increasing the viscosity of the filtrate (using for

example, silicates or glycols) the rate of ingress

is reduced. However, this slowing may not be

sufficient to control wellbore stability and the

mud may have an infeasibly high plastic viscosity.

Minimizing Subsequent Swelling

If invasion of a WBM filtrate cannot be avoided,

appropriate design of the filtrate chemistry may be

used to minimize the swelling response of the

shale. However, even if swelling is effectively

inhibited, filtrate invasion of the shale will

increase the pore pressure and add to possible

mechanical failure of the rock.

Control of ionic strength—The salinity of the fil-

trate should be at least as high as that of the pore

fluid it replaces.

Choice of inhibiting ion—Cations such as potas-

sium should be incorporated into the formulation.

These will replace ions such as sodium found in

most shales to produce less hydrated clays with

significantly reduced swelling potential. Any

inhibitors added to the mud should have sufficient

concentration to remain effective as the filtrate

travels through the shale.

Although potassium ions reduce clay swelling,

they rarely eliminate it. Recently, there have

been attempts to find more effective cations—for

example, aluminium complexes or low molecular

weight, cationic polymers.

Use of cementing agents—An alternative

approach may be to use mud additives that react

with the clay minerals and/or pore fluids present

in shales to produce cements that strengthen the

rock and prevent failure. In field trials, silicate

and phosphate salts have demonstrated the

potential to cement the formation, although some

drilling difficulties unrelated to welIbore stability

have been reported—for example, hole cleaning.

40 Oilfield Review

nMud solids versus rate of penetration.The greater the quantity of solids in themud, the slower the rate of drilling.

12

00

Solids content volume, %

Dril

ling

rate

, ft/

hr 8

4 8 12 16

4

they adhere to the borehole wall and to cut-tings, and they will be added routinely atsurface; formation fluids will contaminatethe mud, perhaps causing flocculation orloss of viscosity, and oxygen may becomeentrained. Temperature, pressure and possi-ble bacterial action may also have signifi-cant effects.

Under these circumstances effective man-agement is not trivial. Nevertheless, basicprocess control techniques have beenapplied rigside for some years to aid in theselection and maintenance of the fluid for-mulation and to optimize the solids-controlequipment—such as shale shakers and cen-trifuges (next page).16 This approach is oftenlinked to incentive contracts, where savingsin mud costs are shared between contractorand operator, and has led to remarkablesavings in mud costs.

For example, with a systems approach todrilling fluid management for 16 wells off-shore Dubai, mud costs were cut in half andreduced as a proportion of total drillingcosts from 6% to 3%. At the same time,hole condition remained the same or bet-ter—this was assessed by looking at holediameter, time to run casing and mud usageper foot of well drilled.17

Such an approach is based on threepremises:• More frequent and more precise measure-

ments, for example five mud checks perday and the introduction of advancedmeasurement techniques (more aboutthese later)

• Efficient data management using massbalance techniques—which track the volumes of chemicals, hole and cut-tings—and computerized data storage and acquisition

• Integration of the management of thesolids control equipment with that of thedrilling fluids.

Solids-control efficiency—the percentageof drilled solids removed versus the totalamount drilled—is central to drilling effi-ciency and is a function of the surfaceequipment, drilling parameters and mudproperties. For example, muds that have alower tendency to hydrate or dispersedrilled cuttings generally give higher solids-control efficiency.

The significance of solids control is thatpenetration rate is closely linked to the vol-ume of solids in the fluid. The greater theamount of solids, the slower the rate ofdrilling (below). Mud solids are dividedinto two categories: high-gravity solids(HGS) comprising the weighting agent, usu-ally barite; and low-gravity solids (LGS)made up from clays, polymers and bridgingmaterials deliberately put in the mud, plusdrilled solids from dispersed cuttings andground rock.

The volume of HGS should be maxi-mized, so that the total volume of solids inthe mud is minimized, while still achievingthe density required to control formationpressures. Therefore, drilled solids must beremoved by the solids-control equipment.However, some solids become dispersed asfine particles that cannot be removed effec-

tively. In this case, the fluid must be dilutedwith fresh mud containing no drilled solids.

But desirable properties are not alwaysoptimum ones. For instance, zero drilledsolids at the bit is desirable. However,achieving zero drilled solids would increasemud costs dramatically.18 It is the job ofmud management to plot the optimumcourse. To do this successfully requiresaccurate and regular input data.

Traditional field practice is to measuremud density and viscosity (using a Marshfunnel) about every 30 minutes at both thereturn line and the suction pit. Other prop-erties—such as rheology, mud solids, fluidloss, oil/water ratio (for OBM), pH, cation-exchange capacity, and titrations for chlo-ride and calcium—are measured onceevery 8 or 12 hours (depending on drillingconditions) using 1-liter samples taken fromthe flowline or the active pit. These deter-minations are then used as a basis for mudtreatment until the next set of measure-ments is made.

To gain better control over the mud sys-tem, a more meaningful monitoring strategymay be required. Simply increasing the fre-quency of traditional measuring techniquesto at least five times a day and making sam-pling more representative of the whole mudsystem has improved control and signifi-cantly reduced the amount of chemicalsused to drill a well.19 However, new typesof measurement are now available. Twonew monitoring systems developed byDowell are the MSM mud solids monitorand the FMP fluids monitoring package.

Mud Solids Monitor—A common indica-tor describing the solids content in the mudis the LGS-HGS volume ratio. This is tradi-tionally measured using the retort, a tech-nique that requires good operator skills,takes at least 45 minutes and often has anerror margin of more than 15%.

The Dowell MSM system takes the placeof the retort. Without complicated samplepreparation, it offers a 10-minute test withan accuracy of more than 95%. The basicmeasurement uses X-ray fluorescence (XRF).A standard software package uses the bar-ium fluorescence and backscattering inten-sity from XRF spectra, together with the fluiddensity to predict the concentrations of bar-ium and water. From these primary outputsthe LGS concentration is also determined.As an off-line measurement, XRF has the

nCleaning the mud. The cuttings-removalperformance of solids-control equipmentdepends on many factors, including thesize of the mesh for the shale shakerscreen, flow rate and density of the drillingfluid, and the size of the cuttings. Decidinghow to use the surface equipment alsodepends in part on the type of mud run.

With the shale shakers, the aim is tochoose a screen mesh size that sieves outas much of the drilled solids as possible,leaving barite, which is finer, in the sys-tem. However, the finer the screen, thelower the throughput of mud and the moreshale shaker capacity required. In thiscase, the choice is either to install an extra

shale shaker or to fit a wider mesh screenallowing more of the solids to remain inthe fluid that must then be diluted withnew, clean mud.

Centrifuges may be used to controlfines. For a low-density mud containingmostly drilled solids, the aim is to stripaway as much of the solids as possible.However, if the mud is weighted, fines-control strategy depends on the liquidphase. If the liquid phase is relativelycheap (for example, a seawater-lignosul-fonate mud), the barite is the most valu-able part of the fluid. In this case, the cen-trifuge is used to remove all the baritewhile the rest of the fluid may be dis-

posed of. However, if the liquid phase isalso valuable (such as in OBM, KCl-PHPAor glycol muds), both phases are worthkeeping. In this case, two centrifugesmay be used. First, to remove the barite,which may be reused. Then, the remain-ing larger solids—assumed to be drilledsolids—may be removed and disposed ofand the liquid returned to the active sys-tem. Clearly, treating mud with the cen-trifuge is a lengthy process and cen-trifuges can typically handle only about15% of the active system.

41April 1994

16. The MUDSCOPE service was originally developedby Sedco Forex, but has subsequently been offeredby Dowell IDF Fluid Services.Geehan T, Dudleson WJ, Boyington WH, Gilmour Aand McKee JDA: “Incentive Approach to Drill FluidsManagement: An Experience in Central North Sea,”paper SPE18639, presented at the SPE/IADC DrillingConference, New Orleans, Louisiana, USA, Febru-ary 28-March 3, 1989.

17. Moore DJ, Forbes DM and Spring CR: “A SystemsApproach to Drilling Fluids Management ImprovesDrilling Efficiency: A Case Study on the NN Platformin the Arabian Gulf,” paper SPE 25646, presented atthe SPE Middle East Oil Technical Conference andExhibition, Bahrain, April 3-6, 1993.

18. Beasley RD and Dear SF: “A Process EngineeringApproach to Drilling Fluids Management,” paperSPE 19532, presented at the 64th SPE Annual Tech-nical Conference and Exhibition, San Antonio,Texas, USA, October 8-11, 1989.

19. Geehan T, Forbes DM and Moore DJ: “Control ofChemical Usage in Drilling Fluid Formulations toMinimize Discharge to the Environment,” paper SPE23374, presented at the First International Confer-ence on Health, Safety and Environment, TheHague, The Netherlands, November 10-14, 1991.

Mud from hole

Down hole

Shale shaker

Solids to wasteBarite(HGS)

New mud

Centrifuge 2

LGS discharge

Degasser

Mud pump

Centrifuge 1

Mud

nFMP Fluid Moni-toring Package sen-sor skid and controlrack. This is the firstprototype skidwhich was devel-oped in France, is acomplete packagecomprising a sensorskid, feed pump,control rack, work-station with monitorand printer, and thesoftware.

nComparison of thesolids content ofmuds using the tra-ditional retort andMSM measurements.In this example theretort measurementoverestimates thebarite content, whilethe MSM measure-ment indicates a rel-atively largeramount of drilledsolids. If decisionshad been based onthe retort measure-ment, necessaryremedial action forthe mud would nothave been carriedout and drilling effi-ciency would havesuffered.

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0800 1000 1200 1400 1600 1800 2000 2200

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LGSBarite

LGSBarite

advantages of more frequent measurement,greater precision and less dependence onoperator skills (right).20

These data provide the basis for informedmud management decisions. For example,using the MSM package offshore Congo,inflows and outflows through the desanderand desilter were monitored. From thesemeasurements, the amount of barite andLGS being dumped on an average day wascalculated. The MSM package showed thatthe desander and desilter were removing alot of valuable barite and not enough of theunwanted LGS.

Analysis of the MSM data showed that ineliminating 11.5 tons [10,430 kg] of LGS perday—the capacity of the desander anddesilter—some 45 cubic meters [1590 ft3] ofmud were lost, requiring a maintenancetreatment including 41.65 tons [37,800 kg]of barite. Based purely on the cost of thebarite, it was found to be more cost-effec-tive to dispose of 60 cubic meters [2120 ft3]of mud and dilute the remaining systemwith new mud requiring only 23.25 tons[22,900 kg] of barite, saving $3339 per day.These findings may vary if mud componentcosts are included in the analysis—manyinhibitive muds have high-value liquidphases—and if the environmental impact ofdumping the mud is considered.

Fluid Monitoring Package—At the heart ofthe system is an in-line skid that continu-ously monitors the rheology, density, pH,temperature and electrical conductivity ofthe mud (above). Data are stored on harddisk and may be viewed on screen in real ordeferred time and on hard copy. Data corre-late with data obtained using standard rigequipment, but of course they are continu-ously delivered.

42 Oilfield Review

For example, rheology is measured usingthree pipe rheometers. Each of these coiledpipes has a different length and diameterand therefore exerts different shear on thesample of mud as it passes at a known ratethrough the pipe. Pressure drop on enteringand leaving each pipe may then be equatedto shear stress. So that data are presented ina form that is comparable to traditionalinformation, shear rate and shear stress areconverted to equivalent Fann 35 viscometerreadings (next page, left). From these, plas-tic viscosity and yield-point readings maybe derived. However, while mud rheologyis traditionally measured at constant temper-ature, the FMP continuous measurement is

made as the mud temperature fluctuatesduring drilling.

The FMP service is currently being field-tested in Europe and Africa. In one field triallasting five weeks, the FMP was tested ontwo wellsites for over 915 hours. The systemwas exposed to three different mud systems—formate, KCl-gypsum, and NaCl saturated—and a wide temperature range—10°C to79°C [50°F to 174°F]. The tests showed thatthe hardware is capable of withstanding therugged demands of drilling, and yieldeduseful mud logs (next page, right).

nMinute-by-minutemud information.This example of anFMP log from pilottests shows how themud parameterschange over 2 hoursand 20 minutes. The right columnincludes bench tests carried out tovalidate the FMPmeasurements.

nComparing plastic viscosity (PV) datagathered in the field from KCl mud usingthe FMP skid with that generated the tra-ditional way using a Fann 35 viscometer.

Take sample

pH skid 2(PH)

Conductivity skid 2

Temperature skid 2

Flow rate skid 2(GPM)

(DEGF)

(MS/C)

Pressurized mudbalance 15.26 ppgFMP 15.23 ppgStart add 50 kgbarite

Barite additionfinished Take sample 2

Take sample 3

Fann PV/YP 37/28

Fann PV/YP 32/20

Pressurized mudbalance 15.91 ppgFMP 15.9 ppg

FMP 15.91 ppg

Bench pH 10.08

Bench pH 9.697

Bench temp. 22°C

Add 2 kg of NaCl

Bench conductivity1.0 mS (25°C comp.)

Bench conductivity8.9 mS (25°C comp.)

15:0

15:10

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127

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Yield point skid 2

Plastic viscosity skid 2

Density skid 2(PPG)

(CP)

(LCF2) 500

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1614

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PV Fann 35

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PComparison of PV Readings Using FMP and Fann Viscometer

10 30 50

50

Future DevelopmentsIt is still early days for these techniques, butsuch measurements, and others in develop-ment, will furnish the information requiredto help control a fully automated mud pro-cessing plant.21

Joint industry field trials are already underway to automate mud management. Theaim is to deliver a system with automatedsolids-control equipment, automated addi-tion of mud chemicals, continuous monitor-ing of key mud parameters, automated mudsystem valve control and tank lineup, andcentral monitoring of integrated processcontrol. A demonstration system has beeninstalled on the semisubmersible rig Sedco712, working in the UK sector of the NorthSea, to allow full-scale evaluation.22

However, it is clear that the driving forcefor automated mud processing, and otherfuture developments, must be more cost-effective drilling, improved employee healthand environmental compliance, andenhanced well performance. —CF

43April 1994

20. Houwen OH, Sanders MW, Anderson DR, ProuvostL, Gilmour A and White DB: “Measurement ofComposition of Drilling Mud by X-Ray Fluores-cence,” paper SPE 25704, presented at theSPE/IADC Drilling Conference, Amsterdam, TheNetherlands, February 23-25, 1993.

21. Hall C, Fletcher P, Hughes TL, Jones TGJ, MaitlandGC and Geehan T: “Mud Analysis and Control forDrilling,” presented at the 4th European CommunitySymposium on Oil and Gas in a Wider Europe,Berlin, Germany, November 3-5, 1992.

Hughes TL, Jones TGJ and Geehan T: “The ChemicalLogging of Drilling Fluids,” paper SPE 23076, pre-sented at the Offshore Europe Conference,Aberdeen, Scotland, September 3-6, 1991.Hughes TL, Jones TGJ, Tomkins PG, Gilmour A,Houwen OH and Sanders M: “Chemical Monitoringof Mud Products on Drilled Cuttings,” paper SPE23361, presented at the First International Confer-ence on Health, Safety and Environment, TheHague, The Netherlands, November 10-14, 1991.

22. The demonstration project is being undertaken bySedco Forex, Dowell, Thule Rigtech and MarineStructure Consultants (M.S.C.) bv. It is partiallyfunded by The Commission of European Communi-ties Thermie project, Shell UK Exploration and Pro-duction, Conoco (UK) Limited and BP InternationalLimited.

Murch DK, White DB, Prouvost LP, Michel GL andFord DH: “Integrated Automation for a Mud Sys-tem,” paper SPE 27447, presented at the SPE/IADCDrilling Conference, Dallas, Texas, USA, February15-18, 1994.Minton RC and Bailey MG: “An assessment of Sur-face Mud System Design Options for Minimising theHealth, Safety and Environmental Impact ConcernsAssociated With Drilling Fluids,” paper SPE 23362,presented at the First International Conference onHealth, Safety and Environment, The Hague, TheNetherlands, November 10-14, 1991.

Pressurized mudbalance 15.91Add 5 kg of NaCl

17:00

4

Pushing Out the Oil with Conformance Control

Daniel BorlingAmoco Production CompanyBairoil, Wyoming, USA

Ken ChanTulsa, Oklahoma, USA

Trevor HughesCambridge, England

Robert SydanskMarathon Oil CompanyLittleton, Colorado, USA

The growing problem of water production and a stricter environmental enforcement on water disposal are

forcing oil companies to reconsider conformance control—the manipulation of a reservoir’s external fluid

drive to push out more oil and less water. The technical challenges range from polymer chemistry to

detailed knowledge of reservoir behavior.

nTwo examples ofproduction reversalduring MarathonOil Company’s con-formance controlcampaign inWyoming’s Big Hornbasin. In each case,Marathon injected apolymer-gel systeminto an injector andnoted the produc-tion response inadjacent producers.Both examplesshow a dramaticreversal of bothdeclining oil rateand increasingwater/oil ratio(WOR)—see straight-line trends in topfigure. On average,each extra barrel ofoil derived fromtheir series of 29treatments costMarathon just $0.34.

Gel treatment

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1000 100

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, BO

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il ra

tio (W

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)

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, BO

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r/oi

l rat

io (W

OR

)

Gel treatment

By late 1984, after several years’ research,Marathon Oil Company laboratories in Lit-tleton, Colorado, USA established a newpolymer-gel system to block high-perme-ability channels within a reservoir andimprove oil recovery. Previous attemptsusing less sophisticated chemistry had failedbecause the chemicals had become unsta-ble at reservoir conditions and also werepartially toxic. But now the chemistrylooked right. During the next three years,Marathon performed 29 treatments with thenew system in nine of its fields inWyoming’s Big Horn basin. Fourteen treat-ments were in carbonate formations, and 15were in sandstones.1

The greatest success occurred wheninjection wells were treated. The Big Hornreservoirs are known to be naturally frac-tured and the injected polymer-gel systemmost likely filled much of the fracture sys-tem between injector and neighboring pro-ducer. This would force subsequent water-

4 Oilfield Review

1984 1985 1986 1987 1988 1989

100 10

Wat

e

For help in preparation of this article, thanks to JimMorgan, BP Exploration, Sunbury-on-Thames, Eng-land; Paul Willhite, University of Kansas, Lawrence,Kansas, USA; Randy Seright, New Mexico Institute ofMining and Technology, Socorro, New Mexico, USA;Stephen Goodyear, AEA Petroleum Services, Dorch-ester, England; Kamel Bennaceur, Dowell, Caracas,Venezuela; Jon Elphick, Dowell, Montrouge, France;Françoise Callet, Schlumberger Cambridge Research,Cambridge, England.In this article, DGS is a mark of Dowell, FLOPERM isa mark of Pfizer Inc., and MARCIT and MARA-SEALare marks of Marathon Oil Company.

1. Sydansk RD and Moore PE: “Production Responses inWyoming’s Big Horn Basin Resulting From Applica-tion of Acrylamide-Polymer/Cr(III)-Carboxylate Gels,”paper SPE 21894, 1990, unsolicited.

2. Coleman B: “DTI’s IOR Strategy” in Best Practices forImproved Oil Recovery. London, England: IBC Tech-nical Services Ltd, 1993.

nThe UK Department of Trade and Industry’s estimate of improvedoil recovery (IOR) potential in the UK North Sea and the proportionexpected to be produced with conformance control.

46%

Not recoverable

11%

Improved oil recovery

Already produced23%

Remaining20%

Primary, secondary recoveryTechnique 106 Barrels of oil

Gas and additional oil recovery by late field depressurization 800

Viscous oil recovery processes 200Hot water SteamIn-situ combustionPolymer

Gas injection 1425

Modified waterflood 40Improved waterfloodSurfactantPolymerFoam flooding

Conformance control 500Polymer gelsMicrobial

Horizontal and extended- reach well technology 2400

drive to enter the matrix rock or fracturesuntouched by the treatment and push outoil. In many cases, a declining productionin the neighboring producer was dramati-cally reversed, staying that way for severalyears (previous page).

Overall, the 29 treatments yielded 3.7million barrels more oil than if the treat-ments had never been done, at a total costof just $0.34 per barrel. Considering theprice of oil at the time ranged from $30 to$24, Marathon had got themselves somevery inexpensive production and a clearsignal that the age of conformance controlhad begun.

What is Conformance Control? In the context of a reservoir produced withsome kind of external fluid drive, confor-mance describes the extent to which thedrive uniformly sweeps the hydrocarbontoward the producing wells. A perfectly con-forming drive provides a uniform sweepacross the entire reservoir; an imperfectlyconforming drive leaves unswept pockets ofhydrocarbon. Conformance control describesany technique that brings the drive closer tothe perfectly conforming condition—in otherwords, any technique that somehow encour-ages the drive mechanism to mobilize ratherthan avoid those hard-to-move pockets ofunswept oil and gas.

In the pantheon of techniques to improveoil recovery, conformance control is rela-tively unambitious, its goal being simply to

April 1994

improve macroscopic sweep efficiency.Most enhanced oil recovery (EOR) tech-niques, for example, also strive to improvemicroscopic displacement efficiency using avariety of surfactants and other chemicals toprize away hydrocarbon stuck to the rocksurface. Conformance control is also lessexpensive than most EOR techniquesbecause the treatments are better targetedand logistically far smaller.

Another factor also favors conformancecontrol. By redistributing a waterdrive so itsweeps the reservoir evenly, water cut isoften dramatically reduced. For manymature reservoirs, treatment and disposal ofproduced water dominate production costs,so less water is good. Environmental regula-tions also push oil companies to reducewater production. In the North Sea, residualoil in produced water dumped into theocean is restricted to 40 ppm, an upper limitincreasingly under pressure from the Euro-pean Community. In environmentally sensi-tive areas such as the Amazon rain forest,water disposal is also a major issue.

In a recent survey by the British Govern-ment Department of Trade and Industry(DTI) that reviewed the full spectrum ofimproved oil recovery (IOR) techniques andtheir potential for the UK North Sea, confor-mance control accounted for a possible fur-ther 500 million barrels of oil (above).2 Thisconstitutes 10% of the total IOR potential of

more than five billion barrels and con-tributes to raising final oil recovery from the43% obtained using primary and conven-tional secondary recovery methods to 54%,an increase of 11%. Unlike many of the IORtechniques reviewed by the DTI, confor-mance control technology was judgedmature enough to use immediately.

Conformance control during waterflood-ing covers any technique designed toreduce water production and redistributewaterdrive, either near the wellbore or deepin the reservoir. Near the wellbore, thesetechniques include unsophisticated expedi-ents such as setting a bridge plug to isolatepart of a well, dumping sand or cement in awell to shut off the bottom perforations, andcement squeezing to correct channeling andfill near-well fractures. Deep in the reservoir,water diversion needs chemical treatment.

Initially, straight injection of polymer wastried but proved uneconomical because ofthe large volumes required to alter reservoirbehavior and because polymers tend to getwashed out. The current trend is gels,which if correctly placed can do the job

45

Problem Solution

Oil

Oil

Gelling solution

Oil

Water

Gel fluid

Protective pressurefluid

Gelling solution

Shale

Oil

Water

Water

Oil

Oil

Cement

Shale

Oil

Water

Oil

Water

WaterGel

nMultiple causes of early water pro-duction during awaterdrive. Top: awatered-out zoneseparated from anoil zone by animpermeable shalebarrier—the solu-tion is to cement inbottom zone. Mid-dle: same as abovebut the shale bar-rier does not reachthe productionwell—cementingdoes not work, sothe solution is toinject gel into thelower zone whilebalancing theupper zone pressurewith inert fluid. Bottom: watered-outhigh-permeabilityzone sandwichedbetween two oilzones—the solutionis to isolate the zoneand inject gel.(Adapted from Mor-gan, reference 3.)

more efficiently with much smaller vol-umes. In the future, potentially less expen-sive foams including foamed gel may betried. Ultimately, reducing water productionmay require a new well. The choice oftechnique or combination of techniquesdepends crucially on the reservoir and itsproduction history.

Take, for example, the case of two pro-ducing zones separated by an impermeableshale, in which the bottom zone haswatered out (right). The first solution is tocement in the bottom zone. Suppose,though, that the shale barrier does notextend to the producing well. Then successwith the cement plug becomes short-livedand water soon starts coning toward the topinterval. The only recourse now is to injecta permeability blocker—some kind ofgelling system—deep into the lower zone.The trick is not letting the gelling systeminvade the upper zone. This can beachieved by pumping through coiled tubingto the top of the watered-out zone whilesimultaneously pumping an inert fluid,water or diesel fuel through the annulus intothe upper zone to prevent upward migrationof the gelling system.

Deep gelling systems are also the answerfor a high-permeability but watered-out for-mation sandwiched between two lower per-meability formations—the classic break-through scenario. A casing patch or cementsqueeze may halt water production momen-tarily, but long-term shutoff requires adeeper block. The fractured reservoir is avariant of this scenario. If natural fracturesare interconnected, they can provide aready conduit for water breakthrough, leav-ing oil in the matrix trapped and unpro-ducible. The solution is to inject and fill thefractures with a gelling system, that oncegelled, forces injection water into the matrixto drive the oil out.

The possibilities are endless, and there areas many solutions to blocking water produc-tion as there are reservoirs to block.3 Thechallenges for the reservoir engineer con-templating conformance control are know-ing why, where and how water is produced,and which water blocking technique to use.In the case of using a gelling system, thereare the additional challenges of being sure

46

that the chemistry is robust enough to gowhere it is intended, deep in the reservoir,and that it is formulated correctly to actuallygel. The combination of these challenges isdaunting and explains conformance con-trol’s checkered history. If the technique ismore widely accepted today, it is onlybecause these challenges are now recog-nized, not because they are resolved.

We’ll next look at the chemistry of gellingsystems, the predominant method of block-ing permeability and redistributing water-drive, and then illustrate the care successfulproponents of the technique must exercisein choosing and implementing treatments.

Gelling System ChemistryPhillips pioneered the first polymer gels forconformance control in the 1970s. Sincethen, research into gelling systems has beenmaintained at an intense level.4 Polymer gelsystems start as a flowing mixture of twocomponents—high-molecular weight poly-mer and another chemical called a cross-linker. At some trigger, each cross-linkingmolecule, tiny compared with the polymermolecule, starts attaching itself to twopolymer molecules chemically linking themtogether (next page, left). The result is a three-dimensional tangle of interconnected poly-mer molecules that ceases behaving like afluid and can eventually constitute a rigid,immobile gel.

The trick in designing these systems isfinding chemicals that are insensitive to the

Oilfield Review

April 1994

nGel formation as cross-linking molecules(red) connect polymer molecules (purple).

3. Morgan J: ”State-of-the-Art of Water Shut-off Well Treat-ments“ in Best Practices for Improved Oil Recovery.London, England: IBC Technical Services Ltd, 1993.Seright RS and Liang J: “A Survey of Field Applicationsof Gel Treatments for Water Shutoff,” paper SPE 26991, presented at the 1994 SPE Permian Basin Oil & Gas Recovery Conference, Midland, Texas, USA,March 16-18, 1994.

4. Needham RB, Threlkeld CB and Gall JW: “Control of Water Mobility Using Polymers and MultivalentCations,” paper SPE 4747, presented at the SPEImproved Oil Recovery Symposium, Tulsa, Oklahoma,USA, April 22-24, 1974.

5. For a general review:Sorbie KS: Polymer-Improved Oil Recovery. Glasgow,Scotland: Blackie, 1992.Woods CL: Review of Polymers and Gels for IOR Applications in the North Sea. London, England: HMSO Publications Centre, 1991.

Pre-gel

Cross-linking Begins

Gel Formed

widely varying conditions of the subsurface,such as temperature, the ionic compositionof the connate water, its pH, the presence ofeither carbon dioxide [CO2] or hydrogensulfide [H2S], and the absorptivity of therock grains, to name a few. The polymermay be naturally occurring or manufacturedsynthetically. The cross-linker may be metalions or metallic complexes that bond ioni-cally to the polymer, or organic moleculesthat bond covalently.

There have been innumerable systemsdeveloped since the 1970s, too many todescribe, so we will concentrate on the evo-lution of a particularly promising system thatuses the synthetic polymer called polyacry-lamide (PA).5 This readily available polymercomprises a carbon-carbon backbone hungwith amide groups, possibly tens of thou-sands of them to provide molecular weightsin the millions (below). In its pure state, thepolymer is electrically neutral, seeming topreclude any cross-linking through ionicbonding. However, when mixed with a littlealkaline solution, such as sodium hydroxide,or when subjected to elevated temperature,some of the amide groups convert to car-boxylate groups. Each of these carries a neg-ative charge. The proportion of amidegroups that convert to carboxylate is calledthe degree of hydrolysis (DH) and typicallyvaries from 0 to 60%. In this form, the poly-

Partially Hydrolyzed Polyacrylamide (PHPA)

Amide Carboxylate Am

Amide Monomer

C

ONH2

Polyacrylam

C

H

C

H

. . . .

C H

. . . . C CC C C

H H

HH H

ONH2 O NH2O–

Na+

NH2 O

H

C C C

C

H

C

H

H

mer is called partially hydrolyzed polyacry-lamide (PHPA) and with its negativelycharged carboxylate groups becomes sus-ceptible to ionic cross-linking.

Efficient cross-linkers are trivalent metalions such as aluminum, Al3+, and chromium,Cr3+. These can be packaged either as sim-ple inorganic ions in solution or within solu-ble chemical complexes in which the triva-lent ion is associated with small inorganic ororganic groups called ligands. Some of thefirst polymer-gel systems from the early1970s used aluminum in the form of alu-minum sulfate. Whatever the choice, thetrivalent metal ion readily links carboxylate

47

nChemical struc-tures of the amidemonomer, poly-acrylamide poly-mer (PA) and par-tially hydrolyzedpolyacrylamidepolymer (PHPA)with its negativelycharged carboxy-late groups.

ide

ide (PA)

C C

H

HC

C

H

H H

O

. . . .

NH2 O

H

High pH

Low pH

Chromium acetate

Cr

O–

. . . .

H

C

O

C CC PHPA. . . .

O– O

C

H

C

CC . . . . PHPA

H2O

H2O

Chromium acetateO

H2O

AcAc

Ac

Ac

AcAc

CrCr

Ac Ac

OH Ac

Cr OH Cr OH Cr

H2O

Ac H2O

Ac

C

H

C

O– O

CC . . . . PHPA

. . . . C

H

C

O

C C

O–

. . . .

Ac is C

H

C

H

O– O

H

. . . .

. . . .

PHPA

Cross-linkerH2O H2OM

O–

C

H H

C

. . . .

NH2 O

. . . . PHPA

O

C

C

C

H

H

C

H

H

. . . . . . . . PHPAC

H

H

C

H

C

O– O

C

H

H

C

H

C

NH2O

nMarathon’s MARCIT gel in three final states depending on concentration, from left:tonguing gel, intermediate strength gel and rigid gel. (Courtesy of Marathon Oil Company.)

nChemical linking of partially hydrolyzedpolyacrylamide polymer (PHPA) moleculeswith trivalent metal ions, indicated generi-cally as M 3+.

nChemical structure of chromium acetatecomplexes as a function of pH and itslinking with PHPA. (Adapted from Tackett JE:“Characterization of Chromium (III) Acetate inAqueous Solution,” Applied Spectroscopy 43(1989): 490-499.)

48 Oilfield Review

Tonguing Intermediate Rigid

groups on different polymer molecules, orpossibly on the same molecule (above). Rel-atively few cross links are needed to ensurethat the polymer-cross-linker mixture gels.

The chemical environment deep in an oilreservoir, however, often conspires to wreckthis idealized picture. In the case of alu-minum sulfate, cross-linking is very muchpH dependent. While the mixture remainsacidic, no gel forms so the treatment fluidscan be safely injected into the reservoir. Butwhen the fluids hit the reservoir, pH risesrapidly and gelling occurs immediately. The

system therefore worked only very near thewellbore and suffered from total lack ofcontrol—gelling time was entirely at themercy of the reservoir environment.

Toward the 1980s, Cr3+ rather than Al3+

was tried as the cross-linker, not because itprovided better cross-linking, but because itpromised better gelation control. The tech-nique to achieve this, though, was not touse Cr3+ directly but rather Cr6+. This ion isinert with respect to cross-linking but can bereduced to Cr3+ using a variety of reducingagents that could be injected with the treat-ment fluids. In theory, this would allow thesystem to be injected deep into the forma-tion before gelling.

In practice, however, there were threeproblems. It was difficult to provide suffi-ciently long gelation times at high tempera-ture; the whole system was sensitive toH2S—itself a reducing agent; and, worst,Cr6+ was recognized as toxic and even car-cinogenic. These problems appeared to beresolved in the mid 1980s when an environ-mentally friendly, controllable chromiumsystem was developed at the MarathonPetroleum Technology Center in Littleton,Colorado, USA.6

Scientists there had the idea of packagingCr3+ as the metal-carboxylate complex,chromium acetate. The acetate group has astructure very similar to the carboxylategroups on PHPA polymer (right). Thus, theCr3+ ion is attracted to both the acetate lig-and within the complex and the carboxylategroups on the PHPA polymer. This slows the

nTwo-stage cross-linking using PHPA and aluminumcitrate, being used by BP Exploration and ARCO in theKuparuk field, Alaska.

6. Sydansk RD: “A New Conformance-Improvement-Treatment Chromium (III) Gel Technology,” paperSPE/DOE 17329, presented at the SPE/DOE EnhancedOil Recovery Symposium, Tulsa, Oklahoma, USA,April 17-20, 1988.

7. Fletcher AJP, Flew S, Forsdyke IN, Morgan JC, RogersC and Suttles D: “Deep Diverting Gels for Very Cost-Effective Waterflood Control,” Journal of PetroleumScience and Engineering 7 (1992): 33-43.Rogers C, Morgan JC and Forsdyke IN: “Deep Divert-ing Gels for Improved Profile Control,” in Oil and GasTechnology in a Wider Europe: Proceedings of the 4thEC Symposium, Berlin, Germany, November 3-5,1992. Aberdeen, Scotland: Petroleum Science andTechnology Institute (1992): 381-399.

O

C

O CH2 O

O C CAl

CH2O

C

O

Aluminum citrate

C

H

C

H

C

H

C

H

HH

. . . .

Stage 1 : Rapid at Low Temperature

C

O

C

NH2 O

CH2O

O C CAl

C

O

OH

O

CH2 CO2 –

Na+

. . . . PHPA

Pre-gel

H H HH

HH

Na+

C

O–O

C

NH2 O

. . . . C C CC . . . . PHPA

C

H

C

H

C

H

C

H

C C HH

. . . .

NH2 O OO

Stage 2 : Rapid at High Temperature

O C CAl

OH

O

CH2 CO2 – Na+

Na+

. . . . PHPA

O

C C CC

H H HH

C C HH

NH2 O OO

. . . . . . . . PHPA

OH

CH2 CO2 –

49April 1994

cross-linking process and ultimately givesthe chemist effective control over gel time.

Substantial laboratory testing showed thatthe behavior of the PHPA-chromium acetatesystem was insensitive to pH from about 2to 12.5, relatively insensitive to ions in for-mation fluids, and untroubled also by H2Sand CO2. Furthermore, it could be formu-lated to give a wide range of gel strengthsand gel times at temperatures up to 124°C[255°F] and even higher. Marathon nowlicenses this system in two forms. ItsMARCIT system using PHPA polymer with amolecular weight of more than five millionis designed for filling and blocking fractures,as used for example in the Wyoming trials(previous page, bottom left). Its MARA-SEALsystem using PHPA with a low molecularweight in the mere hundreds of thousandsand lower DH has reduced pre-gel viscosityand is designed for filling and blockingmatrix reservoir rock.

The chemistry and physics of polymer gelsare complex and often controversial. Onepoint of dispute is whether polymers such asPHPA, even with relatively low molecularweights, as in MARA-SEAL, can be success-fully injected through narrow pore throatsinto reservoir matrix rock. Marathon’s labo-ratory tests suggest they can, although reser-voir conditions may not have been dupli-cated exactly. Others believe that because ofthe interaction of the polymer with the porewalls and the very size of the polymermolecule, the systems have difficulty negoti-ating small pore spaces, limiting injection.The need for matrix-filling gel systems,though, is not in dispute.

BP Exploration and ARCO are currentlytesting a system comprising PHPA and analuminum-based cross-linker that is hopedwill reach deep in the matrix reservoir of theKuparuk field in Northern Alaska. The cross-linker is another metal-carboxylate com-plex, aluminum citrate. But unlikechromium acetate, this links the PHPA intwo distinct temperature-controlled stages(right ).7 In the first stage which occursrapidly in cold water, each aluminum citrate

50 Oilfield Review

Pore throat

Pore

Res

ista

nce

fact

or

200

180

160

140

120

100

80

40

20

0

60

Cold 30-ft sections Warm 2.5-ft section

Hot 10-ft sections

42 days

40 days

37 days

Gelling system movement

nSchematic of polymer molecule elongat-ing within pore throat. As the moleculeelongates, its effective hydrodynamic vol-ume and therefore also its viscosityincrease, impeding injection.

nResistance factors to PHPA-aluminum citrate injection,measured along a 190-ft slimtube packed with sand, inexperiments by BP Exploration. The gelling systemremains fluid in cold and warm sections of the slimtube;it fully gelled only some way into the hot section, once itarrived there 37 days after injection began. (Adapted fromFletcher et al., reference 7.)

molecule bonds to just one polymer car-boxylate site. In the second stage, whichoccurs only above 50°C [122°F], the alu-minum citrate complex can attach to a sec-ond carboxylate group thereby cross-linkingtwo polymer molecules and contributing toproduce a gel network. Because the cross-link itself contains carboxylate groups andthese have an affinity for water molecules,the formed gel may flow in a beaker, yetprovide an adequate permeability block inporous rock.

BP and ARCO’s strategy is to pump thesystem into the reservoir through injectionwells, where the cooler temperature of theinjection water will promote only the first-stage reaction, resulting in a pumpable fluidof low viscosity. Then, as the fluid perme-ates deep into high-permeability sections ofthe reservoir and experiences higher tem-peratures, the second-stage will kick in andenough of a gel will form to divert water-drive to less permeable zones. In prepara-tion for field tests, BP conducted an exten-sive computer simulation of the temperaturedistribution and likely flow patterns of thepolymer-gel system within the reservoir, andalso laboratory studies of the systeminjectability through 190-ft [58-m] longslimtubes packed with sand (below). It istoo early to tell whether their ambitiousplan is working in the field.

The problem of injecting polymer gel sys-tems through the narrow pore spaces ofmatrix is multifaceted and has been a focus

of a three-year Department of Energy projectat the New Mexico Institute of Mining andTechnology in Socorro, New Mexico, USA.8At the pore scale, there are three mainissues. First, some of both the polymer andcross-linker will get adsorbed onto the porewalls during injection. In itself, fluid reten-tion is not a problem as long as most of thetreatment fluid reaches its destination deepin the reservoir. More serious is if the absorp-tivity rates of the two components are differ-ent. Then, the volumetric ratio of polymer tocross-linker will change as the treatmentinvades the formation, possibly compromis-ing control of gelling time. BP’s aluminumcitrate system may overcome this hazardbecause the cross-linker makes its first

attachment to the polymer before injection,rendering the two components inseparable.

The second issue is polymer elasticity.Polymers being long, complex moleculesexhibit a degree of elasticity that makes howthey move somewhat dependent on theirsurroundings. For example, the viscosityobserved in a free polymer solution will notnecessarily be mirrored when the samepolymer is trying to squeeze through a porethroat (left ). In general, polymer elasticityinhibits the progress of treatment fluidthrough porous medium. Third, there is thequestion of pore throats actually becomingblocked by microclusters containing severalpolymer molecules—these may developprior to bulk gelling.9 All three issues arebeing researched and to an extent representthe key to leaping from laboratory evidenceto certainty on what happens in the field.

Inorganic Gelling SystemsAn alternative gelling system that guaranteesinjectability into matrix rock uses simpleinorganic chemicals that have flowing prop-erties nearly identical to those of water.Inorganic gels were discovered in the 1920sand are used to this day for plugging lost cir-culation, zone squeezing and consolidatingweak formations. Their failing for confor-mance control has been a very rapid gela-tion time, but recent innovations using alu-minum rather than silicon have resolved thisproblem. An example is the DGS DelayedGelation System developed by the Schlum-berger pumping company, Dowell.10

The DGS system comprises partiallyhydrolyzed aluminum chloride that precipi-tates to a gel when an activator responds totemperature and raises the system pH abovea certain value (next page). A gel material-izes because aluminum and hydroxyl ionslink with each other in such a way as toform an amorphous, irregular three-dimen-sional impermeable network. The DGS sys-tem is quite insensitive to the subsurfaceenvironment, except for the caution thatdivalent anions in the formation water, suchas sulfates and carbonates, SO4

2– and CO32–,

can enter the system and affect the gel struc-ture. Conformance control with the DGSsystem has been tried with success fromAustralia to South America (see “Profile

8. Seright RS and Martin FD: Fluid Diversion andSweep Improvement with Chemical Gels in OilRecovery Processes, Annual Report for the PeriodMay 1, 1989 - April 30, 1990. Bartlesville, Okla-homa, USA: U.S. Department of Energy, 1991:DOE/BC/14447-8.Seright RS and Martin FD: Fluid Diversion andSweep Improvement with Chemical Gels in OilRecovery Processes, Second Annual Report for thePeriod May 1, 1990 - April 30, 1991. Bartlesville,Oklahoma, USA: U.S. Department of Energy, 1991:DOE/BC/14447-10.Seright RS and Martin FD: Fluid Diversion andSweep Improvement with Chemical Gels in OilRecovery Processes, Final Report and Third AnnualReport for the Period May 1, 1991 - April 30, 1992.Bartlesville, Oklahoma, USA: U.S. Department ofEnergy, 1992: DOE/BC/14447-15.

9. Todd BJ, Willhite GP and Green DW: “A Mathemati-cal Model of In-Situ Gelation of Polacrylamide by aRedox Process,” SPE Reservoir Engineering 8 (Febru-ary 1993): 51-58.

10. Chan KS: “Reservoir Water Control Treatments Usinga Non-Polymer Gelling System,” paper OSEA88134, presented at the 7th Offshore South East AsiaConference, Singapore, February 2-5, 1988.

51April 1994

nDevelopment of Dowell DGS gel as the system pH increases, with postulated gel structure showing aluminumatoms in blue and oxygen atoms in red. Hydrogen will be loosely associated with the exterior, singly bondedoxygen atoms.

pH

Time, hr

Vis

cosi

ty, c

p

0 4 8 12 160

20

40

80

4.0

4.5

5.0

6.0

5.5

Modification Using DGS Gelling System,”next page).

Besides their inherent ability to deeplypermeate matrix rock, inorganic gels haveanother advantage over their polymer-basedcousins. If the treatment fluid gets incor-rectly placed causing a deterioration inreservoir performance, inorganic gel can beremoved with acid. Of course, the acid hasto be able to reach the gel to be able toremove it. Polymer gels, on the other hand,cannot be dismantled easily and are there-fore usually in place for the duration.

If deep penetration in matrix is one keyfactor in the conformance control debate,another concern is contamination of thegelling system through contact with ions inthe formation water. As noted, the DGS sys-tem may be adversely affected by divalentanions. PHPA, on the other hand, bothbefore and after gelling may be affected by

divalent cations such as Ca2+, which are rel-atively ubiquitous in formation waters. Ca2+

ions associate with the carboxylate groupsin PHPA causing free polymer to precipitate.This becomes more of a problem as thedegree of hydrolysis of the polymerincreases, and DH can increase withincreasing temperature. Research initiated atPhillips Petroleum Co. and pursued furtherat Eniricerche SpA, Italy’s national researchcenter for the oil industry situated nearMilan, has identified other polymer typesthat may offer better protection from ionicattack yet still be susceptible to ionic cross-

Profile Modification Using DGS Gelling System

Gilberto TorresCorpoven, S.A.Caracas, Venezuela

nInjection profiles in wells K13 and K35 before andafter pumping DGS gelling system into the lower fivelayers. Conformance is not perfect after the treat-ment, but at least the lower layers are now takingsome of the injected water. (Courtesy of WAPET.)

1. Chang PW, Goldman IM and Stingley KJ: “LaboratoryStudies and Field Evaluation of a New Gelant for High-Temperature Profile Modification,” paper SPE 14235, pre-sented at the 60th SPE Annual Technical Conference andExhibition, Las Vegas, Nevada, USA, September 22-25,1985.

Mourhaf JabriCanning Vale, Western Australia

Carlos MogollonEl Tigre, Venezuela

The following two conformance control case studies describe a producer that is watered-out from coning (Venezuela) and water

injectors that have poor injection profiles (Australia).

52 Oilfield Review

Pro

duct

ion

laye

rs

Injection Profiles

9

8

7

6

5

4

3

2

1

K13

Flow into each layer, %0 20 40 60 80 100

9

8

7

6

5

4

3

2

1K35

Pro

duct

ion

laye

rs

Pre-treatment

Post-treatment

Venezuela

In Venezuela, oil company Corpoven, S.A. has

been evaluating several gelling systems at its

national research center INTEVEP. Laboratory

analysis narrowed its choice to the inorganic DGS

system of Dowell and Pfizer Inc.’s FLOPERM sys-

tem. The FLOPERM system uses a monomer

called melamine—a monomer comprises a sin-

gle chemical group from which polymer is

built—and an organic covalent-bonding cross-

linker, in this case formaldehyde, to form poly-

mer gels in situ.1 In the field, Corpoven tried the

DGS system in two wells, the FLOPERM system

in one well, and both systems in a fourth well

with each system restricted to a different produc-

ing zone.

The most successful treatment was in one of

the two wells receiving the DGS system only. The

treatment was designed to block water coning at

the bottom of an oil producer in a zone 6 ft [2 m]

thick. The reservoir was an 80-md limestone at

9145 ft [2787 m]. Downhole static temperature

was 140°C [284°F], high for most commercially

available gelling systems.

During a period of 10 hours, 300 barrels of

DGS treatment fluid were pumped through tubing

and packer into the watered-out zone at 0.5

bbl/min. Simultaneously, diesel fuel was pumped

down the annulus above the packer into the over-

lying oil zone to prevent the treatment fluid from

entering the oil zone. The treatment fluid was

then displaced with 78 barrels of water and

allowed to gel for a week.

When the well was put back on production, oil

production increased more than 2.5 times and

water cut had dropped 25%. Eleven months later,

36,000 additional barrels of oil had been pro-

duced and water cut was still 15% less than

before the treatment.

Australia

In the Barrow Island field in Western Australia,

Western Australian Petroleum (WAPET) has been

deploying DGS treatments in injector wells to

redistribute waterdrive to low-permeability parts

of their multilayered, predominantly nonfissured

reservoir. In two injection wells, K35 and K13,

the top three of a total of nine reservoir sand lay-

ers were taking almost all the injection

water—about 100 BWPD. The bottom six layers

were getting practically nothing.

In a treatment design that was similar for both

wells, WAPET placed a plug below the third layer

and injected about 400 barrels of DGS system

over three to four days, anticipating that the

treatment fluid would invade at least 20 ft [6 m]

into the reservoir matrix. After allowing the gel

enough time to set, they then reperforated the

lower zones and began reinjecting water. As

might be expected, injection rates were less than

before—74 versus 150 BWPD in K13 and 105 ver-

sus 120 BWPD in K35—due to the plugging

action of the gel. But the injection was better

distributed, as shown by tracer surveys (left). The

top layers still take their fair share, but now the

bottom layers also take some water. Correspond-

ingly, water cut in adjacent producers dropped by

more than 50%.

11. Doe PH, Moradi-Araghi A, Shaw JE and Stahl GA:“Development and Evaluation of EOR PolymersSuitable for Hostile Environments: Copolymers ofVinylpyrrolidone and Acrylamide,” paper SPE14233, presented at the 60th SPE Annual TechnicalConference and Exhibition, Las Vegas, Nevada,USA, September 22-25,1985.Moradi-Araghi A, Cleveland DH and Westerman IJ:“Development and Evaluation of EOR PolymersSuitable for Hostile Environments: II—Copolymersof Acrylamide and Sodium AMPS,” paper SPE16273, presented at the SPE International Sympo-sium on Oilfield Chemistry, San Antonio, Texas,USA, February 4-6, 1987.Albonico P and Lockhart TP: “Divalent Ion-ResistantPolymer Gels for High-Temperature Applications:Syneresis Inhibiting Additives,” paper SPE 25220,presented at the SPE International Symposium on

nAn example of a polymer that may be more resistant to diva-lent cation attack than PHPA. Called poly/vinylpyrrolidone-acry-lamide, this polymer gains stability from the inert pyrrolidonegroups that substitute for the regular amide or carboxylategroups usually found on PHPA.

. . . . C

H

C

C

OO–

C

H

NH2

C

C

O

C. . . . C

N

C

C C

HHC

H

HHHHHH

CarboxylateAmideVinylpyrrolidone

H

H H

O

linking.11 One solution is to use syntheticpolymers in which some amide groups arereplaced by a more inert chemistry that can-not hydrolyze to carboxylate and thereforeremain vulnerable to wandering divalentcations (right).

Part of the Eniricerche effort is directedtoward improving the temperature rating ofpolymer gel systems. Chemical processalways speeds up with elevated tempera-ture, and this makes gelling increasingly dif-ficult to control. The most interesting resultto date in improving gelation control at hightemperature is through use of chromiummalonate, yet another metal-carboxylatecomplex, as cross-linker.12 Malonate, whichhas two carboxylic groups as opposed to thesingle group in acetate or citrate, appears toextend gelation time by an order of magni-tude (below). As a bonus, surplus malonateuncomplexed with chromium seems toretard gelation even more and also scav-enges those divalent cations such as Ca2+

that can precipitate the PHPA polymer.A final challenge in designing polymer

gels is ensuring long-term stability. Most gelsrun the risk of dehydration, a process calledsyneresis that causes shrinkage and loss ofconformance. But it remains an open ques-tion how serious this shrinkage can be, andwhich gelling system, if any, is leastaffected. As with many other aspects ofgelling systems, syneresis remains an activefield of research.

Oilfield Chemistry, New Orleans, Louisiana, USA,March 2-5, 1993.

12. Lockhart TP and Albonico P: “A New Gelation Tech-nology for In-Depth Placement of Cr+3/PolymerGels in High-Temperature Reservoirs,” paper SPE24194, presented at the SPE/DOE Eighth Symposiumon Enhanced Oil Recovery, Tulsa, Oklahoma, USA,April 22-24, 1992.

13. Seright RS: “Placement of Gels to Modify InjectionProfiles,” paper SPE/DOE 17332, presented at theSPE/DOE Enhanced Oil Recovery Symposium,Tulsa, Oklahoma, USA, April 17-20, 1988.

April 1994

nMalonate, suggested as a stable com-plex with chromium for cross-linking, also acts as a calcium divalent cationscavenger.

C

C

O–

O

. . . .

C O–

. . . .

Ca2+ Malonate

O

H H

Treatment Fluid PlacementAfter chemistry, the second major hurdle inconformance control is placement of treat-ment fluid. This shifts attention from thechemist to the reservoir engineer who mustask and be able to answer some tough ques-tions: Given a reasonably functional poly-mer-gel system, what factors determinewhether a reservoir will benefit from treat-ment? And if a reservoir seems a good can-didate, how should the treatment proceed?Via producers or injectors? And using somekind of zone isolation or none? Candidateselection is how the reservoir engineer’schallenge is paraphrased.

The three-year Department of Energy pro-ject at the New Mexico Institute of Miningand Technology has directed attention tomost of these questions, and some guide-lines have emerged.8 For example, if thetreatment fluid is pumped into injectionwells—which according to numerous casestudies seem to give better results than pro-ducers—theoretical studies show that zoneisolation is mandatory when attempting toinject gel into matrix rock porosity but notimportant when filling fracture porosity.13

This is because if a matrix reservoir is filledwith gel in the wrong places, there is liter-ally no conduit remaining for production.However, in a fractured reservoir where gelfills the fractures, the matrix rock stillremains for producing oil.

Ultimately, computer simulation can beinvoked to test whether a proposed treat-ment is likely to work. But this requiresmore than simulation of reservoir fluid flow.Also needed is a chemical simulator thatmodels how the gelling system reacts with

53

the reservoir environment and how gellingconstituents react with each other. Asreported earlier, BP Exploration performedsuch a computer simulation in its planningfor treating the Kuparuk field with a PHPA-aluminum citrate system. Another fluid-flow/chemical simulator, called SCORPIO,is offered by AEA Petroleum Services, whichis based in Dorchester, England.14 This sim-ulator is currently being used to investigatethe feasibility of polymer-gel conformancecontrol in several North Sea fields.15

The prudent operator, of course, will tem-per sophisticated modeling with a gooddose of common sense. In addition, it doesnot hurt to have enough injection and pro-duction data available to fully comprehendhow the reservoir will react if prodded. Sur-prisingly, reservoir production data can besparse and poorly documented. Frequently,production data are known for groups ofwells tied to a common pipeline and not forindividual wells. However, this was not thecase in the Wertz field in Wyoming, USA forwhich Amoco Production Co. began con-templating a series of conformance controltreatments in mid-1991 (below).16

54

nStructure of Amoco’s Wertz field amance control treatments performetional barrels of oil production via and #127. A treatment in well #120of oil production via neighboring p

Case StudyThe Wertz field was a model implementa-tion of a CO2 tertiary flood, and, as a result,field performance had been copiously docu-mented. Not only were individual producersand injectors monitored daily, but flow ratesof the three phases present—oil, water andCO2—were also measured. These measure-ments were made in special substations,one substation for every dozen wells or so,each with elaborate and automatic appara-tuses for sampling each well’s flow in or outand the flow’s breakdown into three phases.

The Wertz producing formation is a 470-ft[143-m] thick aeolian sandstone at an aver-age depth of 6200 ft [1890 m], with 240 ft[73 m] of net pay having 10% porosity and13-md permeability. The formation isbelieved to have some fractures and is oilwet. Sixty-five wells over 1600 acres areused for production and many more thanthat have been drilled for injection—alter-nating water and CO2 injection, commonlyreferred to as water-alternating-gas (WAG)injection. By mid-1991, the field’s fate liter-ally hung in the balance. The field’s totalproduction had dropped precipitously to

#127#125

#84

#142

#120

t Bairoil, Wyoming, USA. Confor-d in well #84 gained 110,000 addi-

neighboring producing wells #125 gained 140,000 additional barrelsroducing well #142.

4000 BOPD from 12,000 BOPD in 1988, asteeper than expected decline during ter-tiary flooding.

After trying several other techniques tohalt the decline, Amoco turned to confor-mance control, eventually completing 12treatments using Marathon’s polymer geltechnology. Ten treatments were in injectorsand two in producers. Some treatmentswere aimed at blocking matrix porosity andsome aimed to place gel in reservoir frac-tures. We’ll highlight one example of each,illustrating with injector treatments sincethese were the more successful. In somecases, the treatments extended the life of apattern by two years. Overall, Amoco esti-mates that for a total cost of $936,000, thetreatments have yielded an increase in pro-ducible reserves of 735,000 barrels—that is$1.27 per barrel.

A crucial preliminary step in all thesetreatments was candidate selection—thecompilation and review of data to deter-mine a well’s suitability for treatment (nextpage). Although any field information couldbe relevant, five data types were deemedparticularly important. They were:

Oilfield Review

Yes

No

Evaluatemature field

Focus oninjection wells?

Low

prio

rity

Inte

rmed

iate

prio

rity

Hig

h pr

iorit

y

Reviewdata

Well history

H2O/CO2Cycling times

Offsetproduction

Injection conformance

Pattern reserve

Cement bond logs

Geol. X section

Pressuredata

Reservoir kH

Favorableindications?

Other

Core studies

Tracertests

Favorableeconomics?

Focus onproduction

wells?

Yes

No

No

Yes

Safety/environmentalcompliance

Economics/authorization

Combination of techniques

Conformancemethod

In-situ foamsurfactant

In-situpolymer gel

Resins

Other

Sandback

Matrix cement

Zoneisolation

Combination of above

Other

NoYes

Selection ofinjection

equipment

• Pattern reserves. If the pattern reservedata indicated that secondary and tertiaryflooding had pushed out most of the oil,there was no reason to try further produc-tion enhancement with conformancecontrol.

• Historical fluid-injection conformance. Ifan injection well historically showed apoor injection profile, the correspondingpattern was obviously a candidate forconformance improvement. In the Wertzfield, Amoco used radioactive tracer sur-veys to log injection profiles.

• Three-phase offset production data. If pro-ducing wells in a pattern showed a cyclicwater and CO2 production that correlatedwith cycles in the nearby injection well,then it was likely this communication wasthrough an unusually high-permeabilitychannel. The pattern therefore requiredconformance control.

• Breakthrough time during the cyclic cor-relation—essentially the time for water orCO2 to travel between injector and neigh-boring producer. This helped estimate thesize of treatments designed to fill the frac-ture space between the wells.

• Well history information—specifically thehistory of all previous attempts to improveconformance in the well, and why theydid or did not work. This information pre-vented unnecessary workover expense.

The first well treated was #84, an injectionwell on the west flank of the field that fedproducers #125 and #127. This well seemedto satisfy the five criteria. An estimated226,000 barrels of reserves remained in thepattern; injection conformance was poorwith no water and very little CO2 enteringthe upper part of the well; injection cyclingwas clearly visible in #125 and #127, withdocumented breakthrough times of 12 and14 days, respectively; and previous confor-mance control attempts with sand had failedbecause of behind-pipe channeling betweenthe upper and lower parts of the well.

The well seemed to require a blocking ofthe high-permeability matrix in the lower

55April 1994

nAmoco’s process logic for picking conformance control candidates in the Wertz field.(Adapted from Borling, reference 16.)

14. Scott T, Sharpe SR, Sorbie KS, Clifford PJ, Roberts LJ,Foulser RWS and Oakes JA: “A General PurposeChemical Flood Simulator,” paper SPE 16029, pre-sented at the 9th SPE Symposium on Reservoir Simu-lation, San Antonio, Texas, USA, February 1-4, 1987.

15. Hughes DS, Woods CL, Crofts HJ and Dixon RT:“Numerical Simulation of Single-Well Polymer GelTreatments in Heterogeneous Formations,” paperSPE/DOE 20242, presented at the SPE/DOE SeventhSymposium on Enhanced Oil Recovery, Tulsa, Okla-homa, USA, April 22-25, 1990.

16. Borling DC: “Injection Conformance Control CaseHistories Using Gels at the Wertz Field CO2 TertiaryFlood in Wyoming, U.S.A.,” paper SPE/DOE 27825,presented at the SPE/DOE Improved Oil RecoverySymposium, Tulsa, Oklahoma, USA, April 17-20,1994.

Postappraisal evaluation

Implementation

56 Oilfield Review

nInjection profilesfor water and CO2in well #84 beforeand at varioustimes after the geltreatment, whichwas confined to thehigh-permeabilityzone at the bottomof the well. Thetreatment dramati-cally improvedinjection confor-mance. (Courtesy ofAmoco Production Co.)

San

d

Dep

th, f

t

San

d

Zone of suspected high permeability

Water

CO2

1 month pre-treatment 3 months post-treatment 10 months post-treatment 12 months post-treatment

6400

6500

6600

1 month pre-treatment 1 month post-treatment 7 months post-treatment 12 months post-treatment

6400

6500

6600

Zone of suspected high permeability

nImproved oil rate and WOR in production wells #125 and #127 for the 30 months following the gel treatment in well #84. The hia-tuses in early 1992 and mid-1993 in well #127 were caused by surface facilities downtime. (Courtesy of Amoco Production Co.)

Oil

rate

, BO

PD

Wat

er/o

il ra

tioWell #127 Well #125

1000

100

10

J F M A M J J A S O N D J F M A M J J A S O N D 1991 1992

J F M A M J J A S O N D 1993 1994

J F M A M J J A S O N D J F M A M J J A S O N D 1991 1992

J F M A M J J A S O N D 1993 1994

J J

Gel treatmentGel treatment

zone and also of the behind-pipe channel.Amoco opted for Marathon’s low molecu-lar-weight polymer-gel technology, and inaddition, mechanically isolated the targetinterval to avoid losing treatment fluid to theupper zone, a necessary contingency thatconsumed 55% of the total treatment cost.Altogether, 650 barrels of the PHPA-chromium acetate mixture were pumped at4 barrels a minute, in a two-stage operationtaking one day.

As with all their subsequent conformancecontrol operations, round-the-clock precau-tions were taken to avoid any environmen-tal contamination by the treatment fluid andto ensure the treatment fluid was beinginjected in the correct proportions. In addi-tion, fluid issuing from the production wellswas monitored to ensure that the treatmentfluid did not somehow bypass the matrixand get produced. Finally, samples of thetreatment fluid taken in the field confirmedthat a rigid gel formed after a few hours.

One month after the treatment, injectionconformance in well #84 showed spectacu-lar improvement with 57% of injected waterentering the upper zone (previous page).Two months later, during a CO2 cycle, 79%of the CO2 was entering the upper zone.The situation was just as good after tenmonths, when Amoco decided to shut offthe entire bottom zone with sand. Thisforced all injection to the upper zone, and

April 1994

injection profiles thereafter indicated con-formance to be practically uniform through-out that zone—a textbook example of injec-tion conformance.

Meanwhile in producing well #125,which had been previously shut in becauseit produced only water, oil started appearingand production was up to 150 BOPD aftertwelve months; the water/oil ratio (WOR)decreased to 40 (above). Later, oil produc-tion began to slip and well #125 was shutin. Nevertheless, the conformance treatmentprolonged the life of this producing well by30 months, furnishing an additional 80,000barrels of oil.

In producing well #127, oil productionrose from 45 BOPD before the treatment to150 BOPD after. During the same time,WOR dropped from 80 to nearly 20. Theimprovement lasted 30 months, five ofwhich were unfortunately interrupted byfacility breakdowns. Altogether, the wellproduced an extra 30,000 barrels of pro-ducible reserves.

The first treatment Amoco performed withlarge volumes of a high-molecular weightpolymer-gel system was in well #120. Thiswell appeared to be in direct communica-tion via fractures with neighboring producer#142, as evidenced by a very rapid one- tothree-day breakthrough time for CO2 injec-tion. Corroborating a rapid communicationbetween the wells was the behavior of well#142. It could produce oil when #120 wasshut in, but its performance would deterio-

rate as soon as #120 started injecting. Otherfactors favoring a gel treatment for #120included an estimated 209,000 barrels ofmissed reserves, poor injection confor-mance with nearly 90% of the water enter-ing a suspected mid-pay fracture, and a wellhistory showing that earlier treatments usingin-situ surfactant foam had failed to improveconformance.

The treatment in #120 was altogether of adifferent scope than the matrix treatment in#84. First, treatment volume totaled 10,000barrels and took seven days to pump, at therate of one barrel per minute. This volumewas estimated to be enough to completelyfill the fractures between the two wells. Sec-ond, no mechanical isolation was usedbecause the treatment fluid was expected tobe able to enter only the targeted fractures.After waiting a few days to let the systemgel, well #120 was once again put on alter-nating water and CO2 injection. As mea-sured by tracer surveys, the conformance forboth fluids was significantly improved (nextpage, top).

Production at #142 still responded to thewater-CO2 cycling, indicating that the gelhad not completely filled the fracture systemand that therefore some communicationremained, but oil rate improved, reaching275 BOPD more than it would have with-

57

nImproved oil rateand WOR in produc-tion well #142 forthe two years fol-lowing the gel treat-ment in well #120.(Courtesy of AmocoProduction Co.)

nInjection profilesfor water and CO2in well #120 beforeand after the geltreatment, whichwas aimed at thesuspected fracturezone in the middleof the well. Thetreatment dramati-cally improvedinjection confor-mance in the upperzone. (Courtesy ofAmoco Production Co.)

58 Oilfield Review

6600

6700

6900

6800

Dep

th, f

t

Water CO2

1 month pre-treatment 1 month post-treatment 7 months post-treatment 12 months post-treatment

Zone of suspected fractures

Well #142

J F M A M J J A S O N D J F M A M J J A S O N D 1991 1992

J F M A M J J A S O N D 1993 1994

J

Gel treatment

Oil

rate

, BO

PD

W

ater

/oil

ratio

1000

100

10

out treatment. WOR dropped to 30 where itremained for more than two years (right).Altogether, the treatment prized out of thetired reservoir an additional 140,000 barrelsof oil.

Amoco’s strategy in the Wertz field neverincluded sophisticated computer simulationto pick conformance candidates. Rather, itrelied on unusually complete field docu-mentation and a well thought-out, methodi-cal approach for candidate selection. In asmall, well understood field, Amoco suc-ceeded in making conformance control aneconomic success. The next years will seewhether this success can be extended tolarger fields—in the Alaskan North Slope,the UK and the Middle East, for example—that are entering their twilight years andwhere the economics are on a significantlylarger scale.

Meanwhile, the chemists remain at theirdesks, fine-tuning their understanding ofgelling, seeking a better polymer, and mov-ing out to new systems such as polymer-gelfoams. Conformance control is here for theduration as long as oil fields continue toproduce water. —HE

Teamwork Renews an Old Field witha Horizontal Well

An integrated services approach to drilling a horizontal well in Lake Maracaibo, Venezuela brought new life to

a watered-out, mature field. A crossdisciplinary cast of geoscientists from Maraven, S.A. and Schlumberger

overcame complex geology and landed a successful horizontal drainhole where previous attempts by other

companies had failed.

59

Leonardo BellosoFernando ChacarteguiBicé CortiulaFlorangel EscorciaTomàs MataElizabeth SampsonMaraven, S.A.Caracas, Venezuela

René CascoJoey HusbandGerardo MonseguiChris TaylorCaracas, Venezuela

Bill LessoSugar Land, Texas, USA

Tony SuárezLos Morochas, Venezuela

For help in preparation of this article, thanks to IanBryant and Mike Kane, Schlumberger-Doll Research,Ridgefield, Connecticut, USA; Eric Cook, Dowell, Tulsa,Oklahoma, USA; Bob Cooper and Curt McCallum, Dow-ell, Sugar Land, Texas, USA; and Larry Hibbard, Anadrill,Sugar Land, Texas, USA. In this article, Charisma, CemCADE, CDN (CompensatedDensity Neutron), CDR (Compensated Dual Resistivity),DSI (Dipole Shear Sonic Imager), ELAN (Elemental LogAnalysis), Impact (Integrated Mechanical PropertiesAnalysis Computation Technique), EARTHQUAKER andMicroSFL are marks of Schlumberger.1. Martins E, Larez NI and Lesso W Jr: “Recovery of Attic

Oil Through Horizontal Drilling,” paper SPE 26334,presented at the 68th SPE Annual Technical Confer-ence and Exhibition, Houston, Texas, USA, October3-6, 1993. Suárez T, Luque R and Contereras L: “A HorizontalWell in a Depleted Reservoir: A Lake Maracaibo CaseStudy,” paper SPE 26998, presented at the Latin Amer-ican/Caribbean Petroleum Engineering Conference(LACPEC), Buenos Aires, Argentina, April 27-29, 1994.

April 1994

V E N E Z U E L A

Caracas

G U

Y A N A

C O L O M B I A

B R A Z I L

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N

0 miles 500

0 805km

LakeMaracaibo

Lagunillas

10 k

m

VLA-8

1 km

C-7

nBlock 1 of LakeMaracaibo inVenezuela. The firstsuccessful horizon-tal drainhole wasdrilled in the C-7sands of the VLA-8reservoir.

A lobster dinner brings out the explorationistin us all, providing a tasty lesson in how toboost recovery. A novice seafood lover maysettle for the tail. Extra work and some spe-cialized tools (a nutcracker and lobster fork)yield substantial rewards from the claws andlegs. To recover that elusive delicacy roe,however, requires motivation, experienceand knowledge of lobster anatomy.

Maraven, S.A., one Venezuela’s threenational oil companies, is going for the

hard-to-get roe in Block 1 of Lake Mara-caibo, Venezuela1 (above). Forty years ofproduction there has left isolated pockets ofhydrocarbon, known as attic oil, in the topsof structural and stratigraphic traps. Recov-ering this attic oil with vertical wells is notusually cost-effective because the thin layer

500

2000

0

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0

500

1000

1500

B/D

VLA-137

VLA-417

VLA-462

VLA-545

VLA-546

VLA-459

VLA-798Well

1000

B/D

of oil in place increases the likelihood ofwater coning.

Taking a new approach, an integratedteam of geoscientists from Maraven andSchlumberger planned, drilled and com-pleted VLA-1035—Lake Maracaibo’s firstsuccessful horizontal well—gaining aneight-fold increase in oil production oververtical wells in the same reservoir.

The motivation for VLA-1035 was pro-vided when Maraven’s parent companyPetroleos de Venezuela, S.A. (PDVSA)launched a development program for LakeMaracaibo. The plan called for generating11 billion barrels of additional oil reservesthrough new wells, horizontal developmentand reworking of older wells.2 Althoughhorizontal drilling had been considered inLake Maracaibo since 1986, attempts byother companies to drill horizontal wellswere unsuccessful because of the complexgeology or completion problems.

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaDrainhole

(Attic)Oil-wconta

East

North

I C O T E A

F

A U L T

nModel of the geologic stAttic is at the crest of a tithe roof of a house.

60

Yet, horizontal drilling seemed the onlyway to produce from Block 1. A verticalwell typically produced 150 barrels of oilper day (BOPD). Most older wells had beenshut in as uneconomic, and the wells thatwere on line typically produced no morethan 150 barrels of oil. Some recent wellsbegan producing water immediately, othersmade water within two months. Early break-through of water was inevitable because ofthe reduced vertical height of pay, reducedreservoir pressure and increased relativepermeability of water to oil.

The Planning StageIn early 1992, Maraven began assessing theeconomic and technical feasibility ofdrilling a horizontal drainhole to recoverremaining reserves. Reservoir engineersevaluated production histories to identifyregions with recoverable oil and later mod-eled drainhole performance. Geophysicists

aaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaterct

2500

ructure of the VLA-8 reservoir. Theghtly folded anticline that resembles

nAverage production over a three-monthperiod in 1992 from a sampling of wells inthe VLA-8 reservoir. The water cut in thefield has increased from 20% in 1960 to85% in 1991.

used three-dimensional (3D) seismic data,having vertical resolution of tens to hun-dreds of feet, to obtain a big picture of thereservoir and identify prospective sands.3

Geologists and sedimentologists examinedcores and logs, with vertical resolutions onthe order of inches to one foot, to identifysands and model their orientation, continu-ity and distribution. Petrophysicists workingwith sedimentologists integrated log andcore data with drilling records, including bitand mud data, for 33 wells in the area. Thisprovided an understanding of the mechani-cal stability of the formation, fluid distribu-tion, oil-water contact location, and flaggedpossible drilling difficulties.

They targeted reservoir VLA-84 in Block 1,bound on the west by the Icotea fault. Itcontains a region of low dips (2° to 10°)called El Pilar and a region of high dips (30°to 45°) called the Attic (left). Since 1954,

Oilfield Review

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VLA-8 has produced 42 million barrels ofthe estimated 118 million barrels of oil inplace. This production reduced reservoirpressure from 3200 psi to 1800 psi at 6700ft [2040 m] in some areas and raised the oil-water contact. Water coning has been aproblem from the beginning, with the aver-age water cut in the field increasing from20% in 1960 to 85% by 1991 (previouspage, top). The influx of water moves hydro-carbons toward the top of traps, creatingisolated pockets of oil. Because of theextensive production in the field, normallydesirable high permeability zones hadwater, whereas low-permeability zones stillcontained oil.

The Attic is considered the last opportunityfor development in Block 1. Three-dimen-sional seismic data, shot in 1990 and cover-ing 235 square km [91 square miles], revealedthe structural complexity of the fold and faultsystems that bound the reservoir, and alsostratigraphic features within the pay sands.The steeply dipping flanks are difficult toimage seismically because a mud layer atthe bottom of Lake Maracaibo absorbs high-frequency seismic energies.

Well-tie sections, time slices and 3D cubedisplays from Schlumberger’s Charismaworkstation contributed to understandingthe structure (right). Productive sands in theAttic are in the C-6 and C-7 horizons, whichhave each been divided into three inter-vals—upper, middle and lower. In addition,seismic attribute sections were generated onthe workstation and interpreted. Seismicattributes, such as signal phase and polarity,can reveal subtle characteristics of a seismictrace. In this case, instantaneous phase sec-tions were particularly helpful in confirmingthe continuity of the C-7 structure. But thesteep dip of the beds prevented determiningan exact location of the C-7 reservoir.

nCharisma workstation displays of 3D seismic data on the C-7 sands of Block 1. Thetwo-way time map (above) shows the elevated Attic area at the C-7 level. The color bardenotes the blue area as the highest structural position. The westward edge of the bluearea represents the contact with the Icotea fault. The structure strikes north-south andshows a slight arch in the middle of the area. Structural dip is visible to the east andstops abruptly at the back fault (green-red contact). These two faults delineate the prin-cipal boundaries of the Attic block.

The amplitude map (below) shows the continuity at the C-7 level. The longest, light-green amplitude event in the middle of the time slice corresponds to the C-7 channelsand as interpreted by the sedimentologists from core analysis. The horizontal drain-hole was located in this event.

2. George D: “Lake Maracaibo to Undergo Major Revi-talization, $9.6 Billion for Development During theNext Four years,” Offshore/Oilman 52, no. 9 (Septem-ber 1992): 25-29.

3. Boreham D, Kingston J, Shaw P and van Zeelst J: “3DSeismic Data Processing,” Oilfield Review 3, no. 1(January 1991): 41-55. Hansen T, Kingston J, Kjellesvik S, Lane G, l’Anson K,Naylor R and Walker C: “3-D Seismic Surveys,” Oil-field Review 1, no. 3 (October 1989): 54-61.

4. In Lake Maracaibo, Maraven names reservoirs afterthe name of their discovery well. In this case, the wellVLA-8 discovered the reservoir VLA-8. Maraven num-bers wells sequentially. Wells in Block 1 have the pre-fix VLA, those drilled in Block 2 have the prefix VLB,etc. VLA-1035 occurs in Block 1 and is the 1035thwell drilled by Maraven in Lake Maracaibo.

61April 1994

400 meters

Amplitude

-128 -64 0 64 128

Crossline

360

2.5P

rodu

ctio

n, m

illion

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rels 2

1.5

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0.5

093

Year94 95 96 97 98 99 2000 01 02

Horizontaldrainhole

2 verticals

1 verticalaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa5400

Vert

ical

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t

5700

6000

6300

6600

6900

0 600 1200 1800 2400 3000 3600

Horizontal displacement, ft

55° 6317 ft MD

C-7 Upper

C-7 Middle

C-7 Lower

55° 7256 ft TD

nHorizontal versusvertical recovery.Reservoir modelingindicated that ahorizontal wellwould recover 2.1million barrels ofoil compared to 0.8and 1.5 millionbarrels for verticalwells. Furthermore,the horizontal wellshould recover 87%of its lifetimeproduction duringthe first four years.

nPlanned trajectoryfor the pilot wellwith three possibledrainhole locations.

Maraven was especially interested in themassive C-7 sands, 60 to 200 ft [18 to 60 m]thick, products of deltaic and fluvial deposi-tional environments (above, middle). Targetsands appeared to be the C-7 upper andlower intervals, with the initial preference byMaraven for the lower one.

Their next step was putting the seismic,log and core data into a reservoir model thatwould help identify the drainhole’s positionin the sand for maximum production. Mod-eling performance of the proposed horizon-tal drainhole in the C-7 sands was accom-plished with a black-oil reservoir simulator.Based on log and core analysis, the modelcomprised a partially anisotropic reservoirwith a horizontal permeability of 250 mdand a vertical to horizontal permeabilityratio, Kv/Kh, of 0.5. In the model, the reser-voir was bounded on one side by an aquifer

62

and on the other by the Icotea fault. Assum-ing that no more vertical wells would beshut in and that water cut would stabilize,Maraven calculated that existing conven-tional wells would recover only 18% of theremaining reserves.

To find the most productive drainholelocation, Maraven modeled performancefor four horizontal drainholes, with lengthsof 584 ft [178 m], 884 ft [307 m], 1200 ft[366 m] and 1600 ft [488 m], in the upper,middle and lower sands. The 1200-ft drain-hole in the C-7 lower sand performed best.Overall, reservoir modeling showed that ahorizontal well would recover 40% to160% more oil than a vertical well (top).

After analyzing the seismic interpretationand the reservoir simulation, Maraven geo-scientists concluded that a horizontal drain-hole could not be drilled without additionalinformation from a pilot well. First, theyneeded to pinpoint the top and thickness ofC-7 with respect to the Icotea fault. Second,they needed to better define the oil-watercontact. At this point, they negotiated withSchlumberger to manage drilling the pilot

well and the subsequent drainhole underMaraven supervision. As Maraven andSchlumberger geoscientists worked togetheron the project, specialists from both compa-nies refined the initial geologic and reservoirengineering studies.

Coordinating the project was Anadrill’sBill Lesso, who had worked with Schlum-berger’s Horizontal Integration Team (HIT),which pioneered an integrated-servicesapproach to drilling horizontal wells. TheHIT group found that a coordinator wasessential to facilitate communicationbetween disciplines and act as a catalyst fordecision making.

The program for drilling and completingthe horizontal well took about 10 weeks(next page, top). Each task in the programwas listed chronologically with its projectedduration and status. This helped identifyboth progress and problem areas. Maravenand Schlumberger geoscientists involved inthe planning met weekly to share informa-tion, discuss interpretations and make rec-ommendations. Once drilling began, theseweekly meetings gave way to daily sessionsat a “mission control” center in Lagunillas,20 miles [32 km] from the offshore rig butlinked to it by phone, fax and data transmis-sion lines. Every morning at 9:00, the teammet to discuss drilling or completion opera-tions—whatever was planned for the next48 hours. The team needed to achieve aconsensus on drilling decisions and be oncall round the clock during critical opera-tions. To keep team members and interestedparties informed, the project coordinatorprepared and distributed weekly updates—one-page summaries that highlightedprogress and issues to be resolved.

Prompt and frequent communication wascritical for weaving together the expertise ofMaraven and Schlumberger specialists. Thissynergy resulted in well-informed decisionsand has become a blueprint that Maraven isusing in other projects (next page, bottom).

Drilling the Pilot HoleThe plan called for an 81/2-inch pilot holedeviated 55°, with three possible drainholetrajectories to follow (above, left). Log datafrom the pilot well would be used to pickthe best drainhole location. In addition todetermining the drainhole trajectory, drillingthe pilot hole gave the team an opportunityto learn how directional drilling equipmentbehaved in the VLA-8 formation.

Oilfield Review

63April 1994

Core analysis

Acquire offset/field data

Structural/stratigraphic analysis

Core mechanical properties analysis

Static reservoir modeling

Dynamic reservoir modeling

Finalize reservoir evaluation-drainhole

Preliminary reservoir study presentation

Evaluation of offset drilling data

Trajectory design

Torque and Drag analysis

Drilling operations plan-tool list

Define pilot strategy

Define well evaluation program

Design completion

Coiled-tubing servicing analysis

Scan lake bed for rig placement

Proximity analysis well resurvey

Study acceptance presentations

Rig mobilization/tripod fabrication

Drilling equipment mobilization

Personnel mobilization

Pre-spud meeting

Start drilling, run conductor pipe to 133/8-in. casing point

1 2 3 4 5 6 7 8 9 10 11

July August September

6 Jul 13 Jul 20 Jul 27 Jul 5 Aug 10 Aug 17 Aug 24 Aug 31 Aug 7 Sept 14 SeptTask

Week

Flow predictions made, total production 1.63-1.80 MMbbl over 12 years

OK: location 417 drainhole approved 29 July

5 August meeting for project decision

OK: first design complete

OK: drillstring optimized

OK: in progress

Vertical option

W/Dowell

Rig Marquette assigned

Rig visit 5 August

Plans in progress

Indicates task completed Official decision needed hereto mobilize rig/services

Well spud date: 31 August

Reservoirengineeringspecialist

Geologyspecialist

SchlumbergerProject

coordinator

Drillingoperationsspecialist

Drillingtechnologies

specialist

Maraven VLA-1035 Project

Leader

Petrophysicsspecialist

Logging,well testing

SchlumbergerWireline & Testing

Cementing,stimulation

Dowell

Directional drilling,

MWD/LWDAnadrill

SeismicGeco-Prakla

nOrganization of the integrated services team.

nTen-week planning schedule for drilling VLA-1035, as ofAugust 5, 1992.

64 Oilfield Review

61/4-in. EARTHQUAKER

mechanicaldrilling jar

Flex joint

9 jointsheavyweight

drillpipe (HWDP)

5-in. drillpipeto surface

26 jointsHWDP

60 jointsdrillpipe

3 jointsHWDP

61/2-in. LWD CDN

7-in. MWD

61/2-in. LWD CDR

Non-mag81/4-in. stabilizer

Non-magpony drill collar

Float sub

63/4-in. bent housing steerable

motor with 11/2° bend

81/2-in. bit

nSteerable bottomhole assembly used fordrilling the pilot well and the horizontaldrainhole.

The well was drilled vertically to a kickoffat 5350 ft [1630 m], then with a build of6°/100 ft [2°/10 m] to 50° deviation using asteerable bottomhole assembly (BHA)(right). CDR Compensated Dual Resistivityand CDN Compensated Density Neutronmeasurements were added to correlate inreal time with log data from nearby wells.LWD logs were later complemented by asuite of wireline measurements comprisinga resistivity log, two porosity logs, a gammaray log and the DSI Dipole Shear SonicImager log. Tool sticking in the build sectionof the pilot well, attributed to overbalancecaused by low reservoir pressure, precludedlogging with a dipmeter tool. The lack ofdip information near the well created aformidable challenge when it came time todrill the horizontal drainhole.

Log data from the pilot well were fed intothe ELAN Elemental Log Analysis program,which fits openhole log measurements to aformation model comprised of mineral andpore fluid combinations (page 66). TheELAN results showed that the C-7 uppersand, with higher clay content than the othersands, had lowest effective porosity, but thehighest hydrocarbon saturations. Logs of theshaly C-7 upper sand indicated oil in the top40 ft [12 m], with a water leg in the cleansand section below (next page). Conse-quently, the team directed their attention tothe C-7 upper rather than lower sand.

Next, petrophysicists used the ImpactIntegrated Mechanical Properties AnalysisComputation Technique5 program to evalu-ate whether the C-7 upper sand could sup-port a horizontal drainhole (page 67). TheImpact program processes a variety ofdata—including bulk volume analysis fromthe ELAN output, vertical and horizontal

stresses derived from logs and core mea-surements, and density logs—to calculatethe stress field at the borehole wall for agiven well inclination and direction. Moreimportantly, it establishes safe mud weightsalong the trajectory in the borehole. Themud-weight range indicates the degree ofdifficulty and expense associated withdrilling a horizontal well.

Vertical stress was derived from log mea-surements of the cumulative density of over-lying sediments. Horizontal stresses wereobtained using differential strain-curve anal-ysis. In this technique, strain gauges areattached to a core sample, which is thenencased in a silicone plug and compressedhydrostatically. Hydrostatic compressioncloses microcracks that developed when thecore was removed. Measuring strain whilethese cracks close gives the ratio of the hori-zontal stresses.

Analysis of DSI data gave the compres-sional and shear velocities needed, alongwith the bulk density, to compute thedynamic elastic moduli. These computa-tions matched the elastic moduli measuredon cores prior to strain curve analysis. TheImpact analysis showed the zone to becompetent and drillable at high angles.

In finalizing the horizontal trajectory, theteam correlated pilot log data with offsetdata from two nearby wells, which showedthat the C-7 upper dipped up about 5° fromthe pilot well, then flattened out and even-tually started dipping down. A 6°/100 feetbuild to 95° was planned to intersect thetarget sand at 6380 ft [1945 m] true verticaldepth (TVD). Markers that could be identi-fied with the LWD gamma ray or resistivitysensors were chosen to verify the approachto horizontal.

Drilling the Horizontal DrainholeThe drainhole was geosteered with an LWDsystem, providing real-time gamma ray andresistivity logs.6 Density and neutron poros-ity data were recorded in downhole mem-ory and used to locate gas, which, ifdetected, would affect completion strate-gies. A sedimentologist at the rig analyzeddrill cuttings to monitor the location of thedrainhole in the target.

The pilot hole was plugged and openedup to allow setting 95/8-in. casing at 6062 ft[1848 m]. When drilling began, the closeinteraction between Maraven and Schlum-berger geoscientists was important in allow-

65April 1994

5. The Impact program helps analyze borehole stability,design fracture jobs and predict sanding. Bruce S: “A Mechanical Stability Log,” paperIADC/SPE 19942, presented at the 1990 IADC/SPEDrilling Conference, Houston, Texas, USA, February27-March 2, 1990.Fleming NH, Ronaldi R, Bruce S and Haryanto J: “TheApplication of ‘Mechanical’ Borehole Stability Theoryto Development Well Planning,” paper IADC/SPE19943, presented at the 1990 IADC/SPE Drilling Con-ference, Houston, Texas, USA, February 27-March 2,1990.

6. Bonner S, Burgess T, Clark B, Decker D, Orban J,Prevedel B, Lüling M and White J: “Measurements atthe Bit: A New Generation of MWD Tools,” OilfieldReview 5, no. 2/3 (April/July 1993): 44-54.Bonner S, Clark B, Holenka J, Voisin B, Dusang J,Hansen R, White J, and Wolsgrove T: “Logging WhileDrilling: A Three-Year Perspective,” Oilfield Review 4,no. 3 (July 1992): 4-21.Allen D, Bergt D, Best D, Clark B, Falconer I, Hache J-M, Kienetz C, Lesage M, Rasmus J, Roulet C andWraight P: “Logging While Drilling,” Oilfield Review1, no. 1 (April 1989): 4-17.

nCDR time-lapse overlay. Superimposing the Laterolog shallow, CDR shallow and CDRdeep resistivity measurements (right track) taken during and after drilling allows moni-toring of invasion. Changes in the resistivity measurements can be used to identifyfluid types. Oil is indicated by the lower Laterolog resistivity readings after invasion offresh mud has occurred. Water is indicated where the LWD resistivity measurementsare lower than the Laterolog shallow measurement.

CDR Deep(ohm-m)

CDR Shallow

Laterolog Shallow

0.2 200

1500

CDR Gamma RayGAPI

Wireline Gamma Ray

166

Wireline Caliperin.

MicroSFL Log(ohm-m)

20000.2

C-7 target

MD

TVD

6700

Washout

6600

Moved Oil

Moved Water

6375

6400

6425

ing the team to respond swiftly to newdevelopments.

The pilot-hole logs were used to constructa dipping, “layer-cake” resistivity model thatcould simulate the LWD resistivity responsein a drainhole for any depth and deviation.These simulated tool responses would guidethe LWD interpreter in advising the drilleronce real-time LWD logs were available.When simulated and measured resistivitiesdiffer, the model is modified by adjustingthe dip of the bed with respect to the bore-hole angle or the depth of the structure. Thisprocess is repeated until the simulated andmeasured resistivity measurements match,indicating the correct model for the depthand dip of the structure.

As the horizontal section began, early cor-relations between the simulated and real-time LWD measurements indicated a steeperdip than expected. To compensate, the teamincreased build angle from 6°/100 ft up to16°/100 ft. Even so, the drainhole exited the

(continued on page 68)

nELAN results for the pilot well. The C-7upper sand showed less effective porositythan the C-7 middle and lower sandsbecause of its higher clay content, but itshydrocarbon saturations were the highest.Resistivity measurements taken duringand after drilling allowed the invasionprofile to be established.

66

1:200 ft 0 150 10000 .01 100 0 75 100 0 100GAPI MD p.u. p.u. p.u.

Gamma Ray

Net Sand

Net Pay

OilPermeability

WaterPermeability

IntrinsicPermeability

SW

Oil

Water

Moved Oil

Fluid Analysis

Illite

Montmorillonite

Sand

Bound Water

Oil

Water

Moved Oil

Combined Model

Mud

cake

Hol

eE

nlar

gem

ent

6599

6400

6699

6799

6900

6500

Bottom of C-7 upper

Top of C-7 upper

TVD MDCoal

md

Oilfield Review

nImpact analysis, calculated from the50° deviated pilot well, used to determinemud weight guidelines for drilling wellsdeviated 50° and 90°. The caliper log inTrack 1 shows some hole collapse thatcorrelates with mud weight below theminimum limit. Track 2 displays threeelastic parameters calculated from acous-tic and density measurements. The rangeof values for Poisson’s ratio, 0.2 to 0.3, andYoung’s Modulus, 3 to 4, indicates a some-what weak, unconsolidated formation.Still, the formation is strong enough tosupport a horizontal drainhole. Mudweight guidelines, calculated for devia-tions at 50° and 90°, are in Track 3. Track4 shows the volumetric interpretation oflithology and pore fluids.

67

1:200 ft -12 12 0 0.5 100

6 psi

p.u.Caliper

Shear Modulus

Poisson’s Ratio

Illite

Montmorillonite

Quartz

Bound Water

Oil

Water

Moved Oil

Combined Model255 0

Mud Weight Gradientlb/gal

Pore Pressure Gradient

Overburden Pressure Gradient

0 10

0 0.56 psi

Young’s ModulusHole Diameter Scale

Hole Enlargement

Mudcake

Stable Borehole PressureGradient Envelope

50°

Stable Borehole PressureGradient Envelope

90°

MD

6600

6700

6800

Safe drillingwindow for 50°deviated well Safe drilling

window for horizontaldrainhole

Poisson’s Ratiolbm/gal

2000

1500

1000

500

Nor

th, f

t

Plan line

Up-dipdirection

35°

8050 ft TD drainhole 2

7276 ft TD drainhole 1

7493 ftpilot TD

oil section at 6748 ft [2057 m], strikingwater (below). The driller jacked up theinclination to 100° to steer the wellbore uptoward the oil bottom. Once it was found,the hole was plugged back. LWD logs fromthis drainhole provided the team with dipinformation crucial for revising the forma-tion model. The team accounted for theeffects of azimuthal changes and high trans-verse dips relative to the well path, causedby the beds dipping up about 35° towardthe fault. Any change in azimuth to the leftwould cause the drainhole to lose elevationin the oil section. A turn to the right wouldcause a gain in elevation.

The revised strategy was to land the drain-hole in the upper section of the target. Oncethere, a 95° inclination would follow thedip until the CDR curve indicated the wellpath exiting into overlying shale. Theazimuth would be closely controlled.

The new drainhole entered the top of thesand at 6750 ft [2057 m] with an inclinationof 87.6°. Logs across the target sand fromthe pilot were then used to navigate thedrainhole, with gamma ray and resistivitymeasurements from the LWD tool as indica-tors. The top of the C-7 upper interval con-tains a series of thin sands and shales eachwith an identifiable gamma ray signature

True

ver

tical

dep

th, f

t

6600

6000

5400

0

5400 fkickoff

68

nPlanned versand cross secthorizontal dragreatly affect

(next page, below). Alternating changes insand and shaliness as found from the pilotwere assigned letters from “a” to “k”—“a, c,e,…” indicated sands, “b, d, f,…” indicatedshales. As the wellbore progressed, correla-tions indicated that the drainhole had pene-trated sandy “a” through shaly “f.” Then theteam decided to steer up to avoid hittingwater. By subsequently drilling from “e”back to “a” and briefly out the top of thesand, they were able to confirm the exact

600 1200 1800 2400

Displacement, ft

t point

41° 6062 ft 9 5/8-in. casing

7276 ftdrainhole 1

TD

7493 ft pilot TD

8044 ftplanned TD

8050 ftdrainhole 2

TD

00 500 1000

East, ft

us actual well paths in plan view (above)ion view (below). The plan views of theinhole show how slight changes in azimuththe drainhole’s position in the sand.

location of the drainhole in the sand. Thiscorrelation of sedimentological faciesbetween pilot and drainhole proved to be apowerful geosteering technique. The drain-hole reached its planned displacement with1112 ft [339 m] of net pay sand.

Completion and ProductionSeveral factors influenced the completion ofVLA-1035. The overall strategy was to pro-duce through slotted liner, but this hingedon the ability to slide the slotted section tototal depth (TD). Also, the slotted sectionneeded to be centralized to avoid extensiveslot plugging. An openhole gas sectionbelow the 95/8-in. shoe found with the CDNlog needed to be hydraulically sealed fromoil production. In addition, low reservoirpressure of 1200 psi required artificial liftfor production.

Consequently, 7-in. casing with the lowersection slotted for production, rather thanliner, was set to surface (next page, top).This would provide the pushing power toreach total depth and guarantee gas isola-tion. CemCADE cementing design and eval-uation software analysis was used to deter-mine pump rates, fluid volumes, surfacepressures and centralizer calculations forcementing. The 7-in. casing was run to thebottom of the hole, and an inflatable exter-nal casing packer was placed above theslotted section to isolate the gas. A port col-lar placed at the top of the horizontal slottedsection directed the cement first into thepacker and then up the annulus betweenthe 7-in. casing and the openhole and 95/8-in. casing. After the packer was inflated,cement was pumped 1500 ft [457 m] abovethe 95/8-in. shoe to provide the hydraulicseal. Finally, 31/2-in. tubing equipped withtwo gas lift mandrels was run.

During the first two weeks of production,chokes ranging from 3/8 in. to 1 in. weretested, with the largest diameter yielding2456 BOPD. With a 5/8-in. choke, the wellaveraged 1400 BOPD and a 4% water cut inthe first five months and continues to produce1000 BOPD with a 12% water cut today.

Maraven has since drilled two additionalhorizontal wells with Anadrill in Lake Mara-caibo, including a reentry well, and isstudying the optimal length of a horizontaldrainhole. In 1994, Maraven plans to drill

Oilfield Review

aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaGas liftmandrels at3838 ft and

5838 ft

Hydraulicretrievable

packer

Port collar

External casingpacker (inflatable) 7-in. casing to

TD at 8050 ft

133/8 in. at 2504 ft

31/2-in. tubing

95/8 in. at 6062 ft

27/8 in.7-in. slotted casing centralized to 6750 ft

Centralizers

nCompletion designfor VLA-1035.aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaaaaaaaaaaaaaaaaaaaaa a aaaaaaaaaaa a aa aaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa aaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaaa b

cd

e fg

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ab

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a b c

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nGeosteering the drainhole. Markers established on thegamma ray log from the pilot well were used to keep thedrainhole in the C-7 upper interval. The drainholepenetrated “a” through “f,” then back to “a.”

11 horizontal wells, building to 36 in 1999.By the year 2000, horizontal wells are pre-dicted to account for 20% of oil productionin Venezuela.

Today, the rapid growth of technologycoupled with greater cost control make itdifficult for any one oil company to have theexpertise to conduct a project like drillingVL-1035. Everyone involved in the project—some two dozen specialists—agreed thatthe spirit of teamwork between operator andcontractor was the key to success.

April 1994

According to Leonardo Belloso, Mar-aven’s production manager who had theultimate authority in the project, “When acommon objective is defined, and bothgroups are aware of the goal and under-stand that success is possible only throughteamwork, then we are 90% there. Goodluck is the other 10%.” —TAL

69