Options for High Temperature Well Stimulation

8/9/2019 Options for High Temperature Well Stimulation

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52 Oilfield Review

Options for High-TemperatureWell Stimulation

Salah Al-Harthy

Houston, Texas, USA

Oscar A. BustosMathew Samuel

John Still

Sugar Land, Texas

Michael J. Fuller

Kuala Lumpur, Malaysia

Nurul Ezalina Hamzah

Petronas Carigali

Kerteh, Terengganu, Malaysia

Mohd Isal Pudin bin Ismail

Petronas Carigali

Kuala Lumpur, Malaysia

Arthur Parapat

Kemaman, Terengganu, Malaysia

Oilfield ReviewWinter 2008/2009: 20, no. 4.Copyright 2009 Schlumberger.

OneSTEP, StimCADE, SXE and Virtual Lab are marks ofSchlumberger.

As wells become deeper and hotter, there is a growing need for high-temperature

matrix acidizing techniques. Newly developed procedures allow acidizing of both

carbonates and sandstones at elevated temperatures. These advances vary from new

chemical agents to simplified fluid-placement techniques.


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Winter 2008/2009 53

Using acids to improve well performance by

removing or bypassing damage has been a

common practice for a long timenearly as long

as the existence of the oil industry itself. In 1895,

the Ohio Oil Company used hydrochloric acid

[HCl] to treat wells in a limestone formation.

Production from these wells increased by several

foldand unfortunately so did casing corrosion.

As a result, acidizing to stimulate production

disappeared for about 30 years.

Acidizing in limestone reservoirs experienced

a rebirth in 1931 with the discovery that arsenic

inhibited the corrosive action of HCl on wellbore

tubulars.1 But acid treatments for sandstones

required a different approach. HCl does not react

easily with minerals that reduce sandstone

permeability, but hydrofluoric acid [HF] does.

Early attempts using HF in sandstones failed

because of plugging from secondary reactions.

This problem was overcome in 1940 with a

combined HF-HCl treatment. The HF in the acid

combination dissolves mineral deposits in

sandstones that hinder production, while the HClcontrols precipitates. These acidizing techniques

have evolved over subsequent years, but the goal

has not changedcreate or restore production

pathways close to the wellbore in a new or

existing well.

Well acidizing, more commonly referred to as

matrix acidizing, is one of two intervention

methods used to restore flow in an oil or gas

formation. The other routehydraulic or acid

fracturingcreates fractures to allow relatively

distant accumulations of oil and gas to flow to the

wellbore. Acidizing works on the formation near

the wellbore to bypass damage or to dissolve it.The choice of fracturing or acidizing to stimulate

production depends on a multiplicity of factors

that include formation geology, production

history and intervention goals.

Well-intervention techniques such as matrix

acidizing play an important role in helping

operators produce all they can from their fields.

Pressure on acidizing experts to develop new

treating formulations and techniques is coming

from several directions. One important need is

extension of acidizing to high-temperature

environments. Use of conventional mineral acids

such as HCl and HF at higher temperatures

above 93C [200F]leads to reaction rates that

are too rapid. These fast rates cause the acid to

be consumed too early, reducing its effective-

ness, and may cause other problems.

Furthermore, as regulations tighten, there is a

greater need within the industry for fluids withreduced environmental and safety risks.2

Conventional mineral acids such as HCl and HF

are difficult to handle safely, corrosive to wellbore

tubulars and completion equipment, and must be

neutralized when returned to the surface.

Additionally, as the bottomhole temperature

increases, corrosion-inhibitor costs rise rapidly

because of the high concentrations required

particularly with some exotic tubulars currently

used in well completions. Finally, conventional

sandstone acidizing techniques typically involve

many fluid treatment steps, increasing the

potential for error.This article will focus on matrix acidizing and

discuss how this technology has been extended

to higher-temperature environments through

development of new fluids and techniques. Case

studies from Africa, the USA, the Middle East and

Asia demonstrate how these techniques are

being successfully employed around the world.

Different Formations

Different Acidizing Chemistry

The first consideration in matrix acidizing any

particular wellhigh-temperature or notis

formation lithology. Carbonate reservoirs are

mostly acid soluble, and acid treatment creates

highly branched conductive pathways called

wormholes that can bypass damage. Conversely,

in sandstone reservoirs, only a small fraction of

the rock is acid soluble. The goal of acid

treatment in sandstones is to dissolve various

minerals in the pores to restore or enhance

permeability. The chemistry and physics fo

treating both types of reservoir have beenextensively studied and are well-understood.

Carbonate reservoirsprincipally limestone

and dolomitereact easily with HCl in

moderate-temperature environments to form

wormholes (above). The reaction rate is limited

primarily by the diffusion of HCl to the formation

surface. Wormholes in carbonate reservoir

increase production not by removing damage

but by dissolving the rock and creating paths

through it.

The formation of wormholes in carbonates is

explained by the manner in which acidizing

affects the rock. Larger pores receive more acidwhich increases both their length and volume

Eventually, this extends into a macroscopic

channel, or wormhole, that tends to receive more

acid than the surrounding pores while it

propagates through the rock. The shape and

development of wormholes depend on acid type

as well as its strength, pump rate and temper

atureplus the lithology of the carbonate

Under the right conditions, wormholes can grow

1. Crowe C, Masmonteil J, Touboul E and Thomas R:Trends in Matrix Acidizing, Oilfield Review4, no. 4(October 1992): 2440.

2. Hill DG, Dismuke K, Shepherd W, Witt I, Romijn H,Frenier W and Parris M: Development Practices andAchievements for Reducing the Risk of OilfieldChemicals, paper SPE 80593, presented at theSPE/EPA/DOE Exploration and Production EnvironmentalConference, San Antonio, Texas, March 1012, 2003.

> Carbonate acidizing. Limestone and dolomite cores treated with HCldevelop macroscopic channels called wormholes (red). These channelsare the result of the reaction of HCl with the calcium and magnesiumcarbonates in the cores to form water-soluble chloride salts.

Carbonate core

Acidizing in Dolomite: 4HCl + CaMg(CO3)2 MgCl2+ CaCl2+ 2CO2+ 2H2O

Acidizing in Limestone: 2HCl + CaCO3 CaCl2+ CO2+ H2O


3/11

to substantial lengths, resulting in efficient use

of acid to bypass damage. In conditions that are

less favorable, the acid creates short channels

that do little to increase production. For any

formation being treated, there is an optimal set

of treatment parameters that creates wormholes

with the most efficient use of acid (above).3

In contrast to carbonate formations, the

quartz and other minerals that make up most

sandstone reservoirs are largely acid insoluble.

Acid treatment for sandstoneHF usually

combined with HClseeks to dissolve the

damaging particulates that block the pores and

reduce permeability (below).4 Acidizing in

sandstone targets damage in the first 0.9 to 1.5 m

[3 to 5 ft] radially from the wellborethe area

that experiences the largest pressure drop during

production and is critical for flow. This area is

typically damaged from migrating fines, swelling

clays and scale deposition. Sandstone acidizing

reactions occur in areas where acid meets

minerals that can be dissolved. The primary

dissolution reactions of the clays and feldspar

with a typical HF-HCl mix form aluminosilicate

products. Sandstone acidizing chemistry is

complex, and the initial reaction products can

react further and possibly cause precipitation.

These secondary reactions are slow compared

with the primary dissolution reactions and rarely

present problems with mineral acids except at

higher temperatures (next page, top).

Extension of matrix acidizing to tempera-

tures above 93C presents the operator with both

possibilities and concerns. The possibilities are

obviousacidizing at higher temperatures

allows stimulation of hot wells using familiar

field procedures. However, at higher tempera-tures, use of HCl causes a host of problems. In

carbonates, the rapid HCl reaction rate at

elevated temperature may lead to face attack

instead of wormhole creation and may create

acid-induced sludge with high-viscosity crudes.

High-temperature problems in sandstones are

different. Clay dissolution may be too rapid,

decreasing penetration by the acid, and

secondary reactions may cause precipitation.

Finally, rapid reaction rates can deconsolidate

the sandstone matrix, creating mobile sand.

Of particular concern in high-temperature

sandstone and carbonate reservoirs is acceleratedcorrosion of tubulars and other wellbore equip-

ment. Although increased injection of inhibitors

may adequately control corrosion rates, the

greater inhibitor loading at higher temperatures

may itself cause formation damage.5

The challenges of extending matrix acidizing

to higher temperatures have led to development

of new treating fluids and techniques. Treating

fluids include acid-internal emulsions to retard

reaction rates in carbonate reservoirs and mild,

slightly acidic chemical agents for treating both

carbonates and sandstones. New techniques

include a simplified sandstone-treating system

that uses laboratory data and predictive

softwarein combination with new chemical

treating agentsto arrive at a simplified

procedure. These new treatments and tech-

niques can be easily understood by examining

some of the laboratory data that were

instrumental in their development.

54 Oilfield Review

> Carbonate dissolution patterns. Wormhole structure is related to the efficiency of the acidizingoperation and can be viewed by plotting the number of pore volumes to core breakthrough (PVBT)versus the flow rate. Porosity patterns obtained from a software model calibrated with experimentaldata illustrate how dissolution proceeds with increasing flow rate. The least efficient acidizingoperation is face dissolutionthe entire matrix must dissolve in order to advance the reaction front.Slightly more efficient at higher flow rates is the creation of large, conical channels. The mostefficient operation occurs at the curve minimum, with creation of highly dispersed wormholechannels. At even higher flow rates, the curve turns upward and large channels, called ramifiedwormholes, form. Increasing to higher flow rates leads again to uniform face dissolution.

Conical Channels

Face Dissolution

Wormholes

Ramified Wormholes

Face Dissolution

Porevolumes

tocorebreakthrough

Flow rate

1.0

0.2

Porosity

> Sandstone matrix. The framework of sandstone reservoirs is typically made up of grains of quartzcemented by overgrowth of carbonates (A), quartz (B) and feldspar (C). Porosity reduction occursfrom pore-filling clays such as kaolinite (D) and pore-lining clays such as illite (E).

A

E

C

B

D


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Winter 2008/2009 55

Laboratory Testing

Testing new treatments and techniques in the

laboratory offers many advantages including

simplicity, cost and avoidance of possible

problems in the field. Good laboratory data will

confirm treatment models and indicate the right

path for successful field operations. Proper

laboratory testing for acidizing techniques can

optimize treatment volumes and pinpoint

potential problem areas as well as confirm

theoretical underpinnings. A strong case in point

is the use of emulsified acids in matrix acidizing

of carbonate formations at higher temperatures.

One way to address the problem of fast

reaction rates at high temperatures is to use

acid-oil emulsions to retard the reaction rate.

These emulsions have been applied in both acid

fracturing and matrix acidizing of carbonates. In

acid fracturing, the emulsions help enhance and

enlarge conductive pathways far from the

borehole. Acid fracturing typically employs

chemical and mechanical diversion techniques

to ensure that the treatment flows to its intendedlocation.6 By contrast, acid-oil emulsions for

matrix acidizing are designed to work close to

the borehole and have lower treatment volumes

than those for acid fracturing techniques.

Acid-oil emulsions for matrix acidizing of

carbonate formations consist of an internal HCl

phase and an external oil phase. Hydrogen ion

transport from the acid droplets to the rock

surface takes place by Brownian diffusion

which dramatically slows the acid reaction rate.7

Laboratory data show that when HCl droplets are

suspended in diesel oil, the reaction rate can be

retarded by more than an order of magnitude(right).8 In addition to the slow reaction rate

3. Fredd CN and Fogler HS: Optimum Conditions forWormhole Formation in Carbonate Porous Media:Influence of Transport and Reaction, SPE Journal4,no. 3 (September 1999): 196205.

Panga MKR, Ziauddin M and Balakotaiah V: Two-ScaleContinuum Model for Simulation of Wormholes inCarbonate Acidization, AIChE Journal51, no. 12(December 2005): 32313248.

4. Damaging particulates may include native clays andcarbonates or material from drilling and workovers.Damage may also occur from other mechanismsincluding clay swelling, scale, organic deposits,wettability changes and bacterial growth.

5. Van Domelen MS and Jennings AR Jr: Alternate Acid

Blends for HPHT Applications, paper SPE 30419,presented at the SPE Offshore Europe Conference,Aberdeen, September 58, 1995.

6. Zaeff G, Sievert C, Bustos O, Galt A, Stief D, Temple L andRodriguez V: Recent Acid-Fracturing Practices onStrawn Formation in Terrell County, Texas, paper SPE107978, presented at the SPE Annual TechnicalConference and Exhibition, Anaheim, California, USA,November 1114, 2007.

7. Brownian diffusion or motion is the random movement ofparticles suspended in a liquid or gas.

8. Navarette RC, Holmes BA, McConnell SB and Linton DE:Laboratory, Theoretical and Field Studies of EmulsifiedAcid Treatments in High-Temperature CarbonateFormations, SPE Production & Facilities15, no. 2(May 2000): 96106.

> Sandstone acidizing reactions. When sandstone formations are treated withHF and HCl, three sets of reactions occur. Close to the wellbore, the primaryreaction of the acids with the minerals forms aluminum and silica fluorides.These reactions rapidly dissolve the minerals and do not yield precipitates.Farther from the wellbore, these primary products undergo slower secondaryreactions to form silica gel, which can precipitate. Finally, at a somewhatgreater distance from the injection zone, a tertiary set of reactions can occur,forming additional silica gel precipitate. The kinetics of the secondary andtertiary precipitation reactions become exponentially more rapid at highertemperatures and may cause sandstone acidizing treatments to fail.

Distance from wellbore

Primary

Secondary

Tertiary

AIFx+ mineral AIFy+ silica gel ; x > y

HF + mineral + HCl AIFx + H2SiF6

H2SiF6+ mineral + HCl silica gel + AIFx

> Emulsions. Acid-oil emulsions decrease reaction rates by limiting accessof the HCl droplets to the reservoir face. Each droplet contains HCl plusother components such as emulsifiers, corrosion inhibitors and hydrogensulfide [H2S] scavengers (top). The extent to which the emulsion retards thereaction rate can be expressed as the retardation factor, FR. This factor is afunction of the ratio of the reaction rate with HCl to the reaction rate of theemulsion. Laboratory core data on carbonates using 15% and 28% HCl instabilized emulsions show that reaction rates can be retarded by factors of15 to 19 times in the temperature range 250 to 350F [121 to 177C] (bottom).(Retardation data adapted from Navarette et al, reference 8.)

250 300 35015

16

17

18

19

20

Retardation

factor,F

R

Reservoir face

Diesel

Emulsifier,corrosion inhibitor,H2S scavenger

HCl

HCl,%15

28


5/11

with the carbonate rock, acid-in-oil emulsions

have other advantages. Their relatively highviscosity improves distribution in heterogeneous

reservoirs, and since the acid does not have

direct contact with well tubulars, corrosion is

reduced. Although emulsified acid systems have

been commonly used for matrix acidizing of

carbonates below 93C, laboratory data indicate

that they can be extended to higher tempera-

tures if properly formulated.The Schlumberger acid-oil emulsion

formulationcalled the SXE-HT systemwas

developed for high-temperature acidizing in

carbonate reservoirs. It consists of an acid phase,

containing a corrosion inhibitor, and a diesel-oil

phase with an emulsifier. These two mixtures are

combined at high shear rates to form an oil-

external acid emulsion. Laboratory data on the

physical properties of this formulation show low

corrosion and pitting for a variety of metals, high

viscosity retention even up to 177C [350F] and

good emulsion stability. For example, a typical

SXE-HT emulsion is stable for at least two hoursat 149C [300F], and this stability time can be

prolonged by increasing the emulsifier concen-

tration. Tests on limestone cores with the

SXE-HT fluid at 135C [275F] confirm its ability

to create wormholes at typical injection rates.

Use of a properly formulated acid-oil emulsion

is one solution for well stimulation at high

temperature. Another approach is to consider a

completely different type of reservoir acidizing

fluid. Data confirm that a different class of

chemicalschelantsallow well stimulation at

conditions that preclude the use of mineral acids.

The term chelation is derived from the Greek

word meaning claw, and chelants are often used

to bind, sequester or capture other molecules

typically metals. Although these agents have been

used frequently in the past to control metals or in

some cases to dissolve scale, their new focus is

well stimulation at elevated temperatures.

The chelants typically used in oilfield services

are complex organic acids (left).9 These

compounds not only bind metals, but also are

active dissolution agents in acidizing reactions.

Well stimulation with chelants yields several

advantages, including retarded reaction rates,

low corrosion rates and improved health, safety

and environmental benefits. While chelants

such as ethylenediaminetetraacetic acid (EDTA)

have been widely used for control of iron precipi-

tation, hydroxyaminopolycarboxylic acid (HACA)

chelants have the additional advantage of

high acid solubility, and their primary role is

matrix acidizing.

The slower reaction rates exhibited by the

HACA chelants at high temperatures have

important implications. In carbonates, slower

rates allow efficient wormhole creation, while in

sandstones there is less possibility of damage to

sensitive formations. Low corrosion is another

important characteristic of HACA chelants. For

example, at high temperature, hydroxyethyl-

ethylenediaminetriacetic acid (HEDTA) exhibitscorrosion rates up to an order of magnitude lower

than those of conventional mineral acids (below

left).10 Significant health and environmental

benefits include lower toxicity, reduced need for

return fluid neutralization and lower

concentrations of corrosion products in these

fluids. Of all these advantages of HACA chelants,

however, the most important may be slower

reaction rates at elevated temperatures.

Coreflood testing in carbonates at elevated

temperatures demonstrates the advantage of

using a chelant rather than HCl to create an

efficient wormhole network (next page).11

Another gauge of chelant effectiveness in

carbonates versus that of HCl is the amount of

acid required to penetrate a formationas

measured by pore volumes to core breakthrough

(PVBT). In one simulation that was scaled up

from laboratory data, PVBT values for HCl and

HEDTA were predicted for acidizing a carbonate

formation at a depth of 2,185 m [7,170 ft], a

bottomhole temperature of 177C, and with

damage that extended 0.3 m [1 ft] from the

wellbore.12 At a pump rate of 0.95 m3/min

[6 bbl/min], the simulation predicted that the

PVBT for HCl was nearly 100 times that for

HEDTAindicating low acidizing efficiency for

HCl at high temperature.

As in carbonates, use of HACA chelants in

sandstones offers a way to avoid the rapid

reaction rates that lead to precipitation.

Laboratory tests on West African sandstone with

an HACA chelant confirm that proposition.

56 Oilfield Review

> Chelants. Typical chelants used in the oil field include both polyaminocarboxylic acids andhydroxyaminopolycarboxylic acids (HACAs). These compounds consist of one to three nitrogen atomssurrounded by either carboxylic [CO2H] groups (EDTA and DTPA) or carboxylic and hydroxyl [HO]groups (HEIDA and HEDTA). Molecular weights range from 177 for HEDTA to 393 for DTPA.

Polyaminocarboxylicacids

Hydroxyaminopolycarboxylicacids (HACAs)

Ethylenediaminetetraacetic acid(EDTA)

HO2C

HO2C

CO2HN N

CO2H

Hydroxyethyliminodiacetic acid(HEIDA)

NHO

CO2H

CO2H

Diethylenetraminepentaacetic acid(DTPA)

HO2C N

HO2C

N CO2H

CO2H

N

CO2H

Hydroxyethylethylenediaminetriacetic acid(HEDTA)

CO2H

HO

NHO2C

CO2

HN

> Corrosion testing. Four-hour corrosion tests at350F were performed on two metallurgies withthree acid-stimulation componentsa 20% byvolume sodium HEDTA chelant, a 15% by volumeHCl and a 9-to-1 mud acid (9% by weight HCl to1% by weight HF). Corrosion rates for the chelantare very low at 0.01 lbm/ft2 [0.049 kg/m2] for bothchrome and nickel steels. In contrast, corrosionrates using conventional HCl and HF treatmentsare 5 to 10 times higher for these metals.

HEDTA HCl Mud acid0

0.02

0.04

0.06

0.08

0.10

0.12

0.14

0.16

0.18

Corrosionrate,

lbm/ft2

80 Nickel steel

13 Chrome steel


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Winter 2008/2009 57

The Nemba reservoir is one of a group of

production zones lying offshore Cabinda,

Angola.13 This layered reservoir consists of varying

thicknesses of sandstone, limestone and shales.Although some high-permeability streaks exist

due to fissures and fractures, permeability

elsewhere is low and temperature is high

149C. The Nemba formation contains high levels

of native calcium carbonate, making the

formation particularly difficult to acidize at

elevated temperatures without causing deconsoli-

dation. Prior treatment and workovers in the

Nemba formation had caused significant damage

related to carbonate scale. Nemba sandstone

samples represent good candidates for evaluating

the use of chelants in high-temperature acidizing.

Ten core samples were taken from the Nemba

field over a narrow depth interval at about

3,534 m [11,595 ft] and subjected to a variety of

experiments with an HEDTA chelant. These

experiments measured composition, examined

metals evolution during reaction and determinedpermeability. The composition of the Nemba core

samples ranged from 5% to 44% calcium

carbonate with significant amounts of feldspar

and chlorites. Two different procedures were

performed in the laboratory to determine the

results of HEDTA treatmentslurry reactor

tests and coreflood permeability tests.

The slurry reactor tests on the Nemba

sandstone samples used an isothermal, stirred

reactor to measure product composition as a

function of time. Powdered sandstone samples

containing 24% and 44% carbonate levels were

treated in the reactor with HEDTA at 149C.

Samples of the reaction mix were withdrawn over

time and analyzed by inductively coupled plasma

emission spectrometry. For both carbonate levels

the concentrations of calcium, silicon, aluminum

and magnesium rose smoothly over time with nodecreases that would indicate precipitation.

The same slurry reactor test was repeated fo

a 30% carbonate-containing sample using a

conventional 9:1 mud acid.14 In this experiment

concentrations of calcium and other component

showed an initial rise followed by a decrease

indicating precipitationa common cause o

sandstone treatment failure. The slurry reactor

data on HEDTA suggest that this chelan

dissolves the pore-filling and blocking minerals

at high temperature without causing precipi

tation. These positive results for HEDTA were

followed by coreflood tests at two carbonate

levels. Results from these tests show that the

9. Frenier WW, Wilson D, Crump D and Jones L: Use ofHighly Acid-Soluble Agents in Well StimulationServices, paper SPE 63242, presented at the SPEAnnual Technical Conference and Exhibition, Dallas,October 14, 2000.

10. Frenier W, Brady M, Al-Harthy S, Aranagath R, Chan KS,Flamant N and Samuel M: Hot Oil and Gas Wells CanBe Stimulated Without Acids, paper SPE 86522,

presented at the SPE International Symposium andExhibition on Formation Damage Control, Lafayette,Louisiana, February 1820, 2004.

11. Frenier et al, reference 9.


13. Ali S, Ermel E, Clarke J, Fuller MJ, Xiao Z and Malone B:Stimulation of High-Temperature Sandstone Formationsfrom West Africa with Chelant Agent-Based Fluids,

paper SPE 93805, presented at the SPE EuropeanFormation Damage Conference, Scheveningen,The Netherlands, May 2527, 2005.

14. A conventional 9:1 mud acid is 9% by weight HClcombined with 1% by weight HF.

> Carbonate core tests. A coreflood test was performed on Indiana limestone with 15% HCl at 150F[65C]. A photograph of the core face shows dissolution ending in a single dominant wormhole ( topleft). A longitudinal CT scan of this core indicates that this single wormhole extended the entirelength of the sample (top right). Similar testing was carried out on a limestone sample with HEDTA at350F and the same flow rate (bottom left). Use of a chelant resulted in a complex network ofwormholes at the higher temperature level (bottom right).

CO2H

HON

HO2C

CO2HN

HCl


7/11

chelant significantly increases permeability in

the damaged cores (left).

In aggregate, the laboratory results on

carbonate and sandstone samples provide an

advance in overcoming problems associated with

acidizing in high-temperature environments. In

contemplating the scale-up of laboratory data to

actual field operation, treating carbonates repre-

sents a more direct extension of the technology

since secondary precipitation reactions are not

present. Complex, multilayer sandstone forma-

tions present a more difficult problem since both

complicated mineralogy and precipitation

reactions must be considered. Job success in

sandstones can be improved by using a geo-

chemical simulator package called Virtual Lab

software that optimizes stimulation parameters for

a variety of fluids and bottomhole conditions (next

page, left).15

Field results from the application of these

advances in high-temperature acidizing confirm

their potential.

Acidizing High-Temperature Carbonate Wells

The carbonate reservoirs of the Smackover

formation, located in the southeastern USA, have

been prolific producers of oil and gas since their

initial discoveries in 1937.16Although interest in

this formation continues, many of the wells

drilled years ago now require stimulation to

boost declining production. High-temperature

gas wells drilled in Alabama Smackover dolomite

20 years ago have been acidized with good results

using oil-HCl emulsions.17 These retrograde

condensate wells reach a depth of 18,500 ft

[5,640 m] and can attain bottomhole tempera-tures of 320F [160C] and static bottomhole

pressures of 2,500 to 4,000 psi [17.2 to 27.6 MPa].

The treatment and production history of one of

these wells illustrates application of retarded

emulsions at high temperature in carbonates.

The gas well treated in the Alabama

Smackover field with a retarded oil-HCl emulsion

was drilled and completed in 1986. By 1998, gas

and condensate production from the well had

declined significantly. Prior to treating the well

with the emulsion, two workover operations were

performed. First, withdrawal of a chemical

injection string allowed additional perforations.

Next, tubular scale was removed using 15% HCl.

This well was then treated with nearly 214 bbl

[34 m3] of an HCl-diesel emulsion at a rate of

9 bbl/min [1.43 m3/min].18 Immediately after

treatment with the retarded emulsion, gas

production more than doubled, with a smaller but

58 Oilfield Review

15. Ali S, Frenier WW, Lecerf B, Ziauddin M, Kotlar HK,Nasr-El-Din HA and Vikane O: Virtual Testing: The Keyto a Stimulating Process, Oilfield Review16, no. 1

(Spring 2004): 5868.16. The Smackover Formation, http://www.visionexploration.

com/smackover.htm (accessed October 20, 2008).

17. Navarette et al, reference 8.

18. The composition of the emulsion as % by volume was30% of an HCl solution (20% by weight HCl in water)mixed with 70% diesel oil.

19. Nasr-El-Din HA, Solares JR, Al-Mutairi SH andMahoney MD: Field Application of Emulsified Acid-Based System to Stimulate Deep, Sour Gas Reservoirsin Saudi Arabia, paper SPE 71693, presented at the

SPE Annual Technical Conference and Exhibition,New Orleans, September 30October 3, 2001.

20. Cocoalkylamine is a cationic surfactant that includes

high concentrations of several long-chain acids thatinclude lauric, myristic, palmitic and caprylic varieties.

21. Nasr-El-Din HA, Al-Dirweesh S and Samuel M:Development and Field Application of a New, HighlyStable Emulsified Acid, paper SPE 115926, presentedat the SPE Annual Technical Conference and Exhibition,Denver, September 2124, 2008.

22. Like the cocoalkylamine, tallow amine acetate is acationic mixture of acids. However, this emulsifier haslonger carbon chains and contains some double bonds.


> Sandstone and chelants. Laboratory permeability tests were carried out

on Nemba sandstone cores with varying carbonate levels before and aftercoreflood treatment with sodium HEDTA at 149C (bottom). In the 24%carbonate sample, the chelant increased permeability (k) by a factor of 25.In the 12% carbonate sample, permeability increased by 35%. Samples ofthe cores were photographed using a scanning electron microscope beforeand after treatment with an HEDTA chelant. Before treatment, the sandstoneshows pore blocking as a result of dolomite and chlorite particles in additionto quartz overgrowth. After treatment, the sample shows significant removalof the pore-blocking minerals.

24% carbonatesample

12% carbonatesample

Permeability,

mD

0

1

2

3

4

5

k(final)

k(initial)

Pretreatment

Posttreatment

CO2H

HON

HO2C

CO2HN


8/11

Winter 2008/2009 59

still significant increase in condensate production

(right). Two other nearby gas wells were also

treated with the retarded emulsion and experi-

enced similar production increases.

Although acid-oil emulsions have been

employed for many years, additional focus on the

details of the technique has yielded significant

improvements. A case in point is their use in

treating a group of deep, high-temperature wells

in the Middle East. These wells are located in

eastern Saudi Arabia and produce nonassociated

sour gas at a depth of about 3,500 m [11,500 ft].

The producing zone lies in the Khuff formation

and is composed of dolomite layers intermingled

with limestone. Bottomhole temperatures are in

the range of 127 to 135C [260 to 275F].

Stimulation efforts have been conducted on a

regular basis by the operator to enhance perme-

ability and remove drilling mud damage. Bothstraight HCl and acid-in-diesel emulsions have

been used for stimulation of gas wells in this

formation with varying results. HCl is an effective

stimulation agent but is highly corrosive at the

higher temperatures encountered in these wells.

An acid-oil emulsion was found to be effective in

providing stimulation without corrosion, but field

application showed the need for optimization of

the emulsifier formulation.19Work to improve the

emulsifier was concentrated on two areas

reduced quantities and improved field operations.

Earlier field tests of acid-in-diesel emulsions

to stimulate wells in the Khuff formation used

28% by weight HCl in a 30% by volume acid and

70% by volume diesel emulsion. The emulsifier

was a cocoalkylamine at 0.08 to 0.11 m3 [0.48

to 0.71 bbl] per 3.78-m3 [23.8-bbl] emulsion

loading.20 The field application showed that

although the emulsion was effective at

stimulating production, further improvements

were needed. Emulsifier loadings were high, and

the emulsion often broke at ambient condition

in the field, necessitating remixing and quality

control in the field before use. Both of these

cocoalkylamine emulsifier attributes mean

longer operation times and higher cost.

The operator, therefore, embarked on a

program to develop and test an improved

emulsion for use in stimulating the deep, high

temperature gas wells in this formation.21 Results

from laboratory testing of more than 10 differen

emulsifiers showed that beef-tallow amine acetatewould be more effective than the cocoalkylamine

formulation.22 This new emulsifier could be used

at 25% of the previous loading to make stable

emulsions with no remixing at both ambient field

conditions and high temperatures. In a four-wel

pilot campaign, the new tallow amine emulsifie

was successfully employed. Mixing times in the

field were reduced by 25% and poststimulation

production rates exceeded expectations.

Acid-in-oil emulsions are not the only option

for hot carbonate well stimulation; chelants can

also be used successfully, as illustrated by a well in

a Middle Eastern carbonate reservoir.23 Afte

completion, the well was not flowing, and drilling

mud filtrate damage in the formation was

suspected. Despite the need to stimulate the wel

to start production flow, the operator had concern

about the high bottomhole temperature110C

[230F]and the formation lithology at a

measured depth of 2,620 m [8,600 ft]. At thi

> Reaction simulations in sandstone. Virtual Labsoftware is a prediction system that determinesoptimal acidizing parameters for sandstonetreatment. This semiempirical system is based on

laboratory data taken from samples of theformation being considered for treatment. In thefirst step, slurry reactor tests are carried outusing acid and crushed solids (top). Analysis ofeffluent solutions allows determination ofreaction kinetics and identification ofprecipitates. In the second step, coreflood testsdetermine permeability and porosity at reservoirconditions (middle). In the final step, all the dataare combined with radial-flow simulations todetermine the best acidizing treatment (bottom).

Slurry Reactor Tests

Reservoir Coreflood Tests

Radial-Flow Simulations

> Smackover well production history. Gas and condensate production from this well declined steadilyover time reaching levels of 3.4 MMcf/d [96,200 m3/d] of gas and 150 bbl/d [23.8 m3/d] of condensatein August 1997, immediately before treatment. After treatment with an acid-oil emulsion, gas productionincreased to more than 9 MMcf/d [255,000 m3/d] while condensate rose to 200 bbl/d [31.7 m3/d]. Sixmonths after treatment, gas production had fallen off somewhat but was still more than twice thevalue prior to treatment. In the same time period, condensate production fell slightly but retainedmost of the treatment-related production increase.

Gasproduction,

MMcf/d

Condensateproduction,

bbl/d

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9/11

depth, the limestone-dominated formation has

dolomite streaks containing significant amounts of

entrapped gas. Surface facilities were limited in

the amount of gas that could be handled to a

gas/oil ratio (GOR) of 440 m3/m3 [2,500 ft3/bbl].

Any stimulation to initiate flow in the well had

to avoid gas production and keep the GOR

below this limit by minimizing stimulation of the

dolomite streaks.

A chelant from the HACA family was the

obvious choice for the stimulation job. Chelants

in the HACA group exhibit enhanced reaction

rates with limestone and more limited reaction

with dolomitesan important factor for the

success of this treatment due to the entrapped

gas. A treatment plan for this well was developed

using the Schlumberger StimCADE software for

acid placement. This plan called for using coiled

tubing to place an HACA chelant into a narrow

zone of the limestone matrix at 2,620 m. The

software predicted a 1.5-m radial penetration by

the HACA chelant.

Stimulation treatment was carried outwithout incident. A preflush of a solvent mixed

with water preceded the chelant to aid flowback

by making the formation water-wet. Treatment

pressure averaged 8.3 MPa [1,200 psi], and the

chelating injection rate was 0.056 m3/min

[0.35 bbl/min]. After treatment was complete,

the operator displaced the well with diesel and

pulled the coiled tubing. Positive results from the

treatment with the chelant were immediately

apparent. Oil production increased from the

initial nonflowing state to 96 m3/d [600 bbl/d].

This oil production increase was accompanied by

a GOR increase of only 264 to 299 m3/m3 [1,500 to1,700 ft3/bbl]well within the operators limits.

Results from these cases confirm that

chelants are useful for stimulation of hot

carbonate reservoirs. This capability is also

present for sandstones.

Acidizing High-Temperature Sandstone Wells

A West African well drilled in 1984 typifies the

choices an operator must make when confront-

ing the need for acidizing a high-temperature

sandstone formation.24 This well, completed at a

depth of 2,360 m [7,743 ft] in a deltaic sandstone

formation with 15% carbonates, had a bottomhole

temperature of 128C [263F]. During a nearly

20-year period, oil production had declined from

490 m3/d [2,500 bbl/d] to 224 m3/d [1,408 bbl/d]

with a corresponding increase in water output.

The water, first noted in 1991, had increased to

30% by 2003. The effect of the water on comple-

tion equipment had been observed during a prior

60 Oilfield Review

> Tiong field. The offshore Tiong field is located 260 km [162 mi] off thecoast of central Malaysia. This sandstone field covers an area of about20 km2 [7.7 mi2] and, along with nearby Kepong and Bekok fields, producesoil and associated gas (inset bottom). These fields send oil and gas bypipeline to a gathering point at Kerteh on the mainland. From Kerteh, oiland gas are sent by pipeline to Kuala Lumpur, Singapore and otherprocessing facilities (not shown).

Kuala Lumpur

Kerteh

Singapore

Kepong/Tiong/Bekok

MALAYSIA

1000 mi

0 100km

Kepong

Tiong

Bekok

GasOil

> Tiong field stimulation results. The OneSTEP procedure performed on the Tiong well in April 2007had immediate positive results from the chelant treatment. Oil production increased from about16 m3/d [101 bbl/d] to more than 70 m3/d [440 bbl/d]. Similarly, gas production increased from lessthan 20,000 m3/d [0.7 MMcf/d] to about 85,000 m3/d [3 MMcf/d].

January 2007 April 2007 June 20070

50,000

100,000

150,000

200,000

250,000

300,000

350,000

400,000

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Oilflow,

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10/11

Winter 2008/2009 61

well intervention to replace gas lift system

components. The scale deposits on the gas lift

mandrels were so severe that a 71-mm [2.8-in.]

gauge cutter could not pass below 875 m [2,870 ft].

Faced with concerns about corrosion and

possible damage to the formation using conven-

tional acidizing, the operator chose to treat the

scale problem with an HACA chelant. The

treatment goal was to use a mild fluid that would

remove carbonate scale and not damage the

sandstone formation. The well was treated with

the HACA chelant using coiled tubing with a

rotating jet to spray and soak the areas

containing the gas lift components. Following

treatment, the fluids used in the operation were

displaced with water and the gas lift system was

restarted. A gauge cutter was run through the

entire length of the wellbore and encountered no

obstructions. After treatment, oil production

increased to 402 m3/d [2,528 bbl/d], indicating

removal of scale and possible stimulation of

the sandstone.

As illustrated by the treatment in this WestAfrican well, using chelants in sandstones with

conventional fluid placement plans is often quite

effective. Schlumberger has extended the utility

of these new chemicals in sandstones with its

OneSTEP technology. This technology uses a

unique chelant fluid and simplified placement

techniques to stimulate production with less risk

of damage and precipitates. This fluid

substantially reduces the number of required

stages during acidizing. Petronas Carigali

recently employed this technology to stimulate

one of its offshore wells in Southeast Asia.

The Tiong field lies off the western coast ofMalaysia in 77 m [253 ft] of water (previous page,

top). Discovered in 1978, the field began

producing oil and gas in 1982. Tiong is a

sandstone formation with a high bottomhole

temperature109C [228F]. After experiencing

declining production and noting a high skin value

for the formation, Petronas evaluated several

Tiong wells as candidates for acidizing

treatment.25 Tests on core samples from the

candidate wells indicated formation damage from

kaolinite fines and calcite. Petronas selected a

well for the acidizing tests and chose the

OneSTEP system for its operational simplicity

and use of chelants (below).26 This combination

marries a low risk of secondary and tertiary

reactions that might cause precipitation with

fewer fluid stages and simplified logistics. Other

benefits accrue from low corrosion rates and a

good health, safety and environmental footprint.


25. Skin is a dimensionless factor calculated to determinethe production efficiency of a well by comparing actual

conditions with theoretical or ideal conditions. A positiveskin value indicates some damage or influences that areimpairing well productivity. A negative skin valueindicates enhanced productivity, typically resultingfrom stimulation.

26. Tuedor FE, Xiao Z, Fuller MJ, Fu D, Salamat G, Davies SNand Lecerf B: A Breakthrough Fluid Technology inStimulation of Sandstone Reservoirs, paper SPE 98314,presented at the SPE International Symposium andExhibition on Formation Damage Control, Lafayette,Louisiana, February 1517, 2006.

> OneSTEP technique. Conventional sandstone acidizingusually with HFis a complex processinvolving several pieces of equipment and many sequential steps (left). As many as six acid tanks andtwo brine tanks may be employed, and five stages with 25 steps may be carried out, depending on thetype of diversion technique. In conventional treatment, brine preflush removes and dilutes acid-incompatible components. Similarly, HCl preflushing removes calcites prior to the main HF treatment. Icontrast, OneSTEP treatment typically uses only two acid storage tanks and one brine tank andrequires significantly fewer treatment steps (right). This treatment simplicity is a result of twofactorsuse of a chelant instead of HF and employment of Virtual Lab predictive software before thejob is started. The chelant eliminates problems with secondary and tertiary reactions, while Virtual Labtesting ensures that any potential problems are addressed before the job begins.

Conventional Fluid Placement

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Overflush

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Step Fluid TypeTreatment Stage

Prior to carrying out the treatment

Schlumberger calibrated the Virtual Lab mode

using results from well testing before running

simulations. The well tests determined

formation dissolution kinetics, measured

physical properties of the rock and compared

treatment options in radial-flow tests. The fina

choice for the treatment fluid at Tiong was a

chelant plus other additives. With this chelant

fluid, the OneSTEP treatment was carried out a

the Tiong well in April 2007. No operationa

problems were encountered and the test wa

successfuloil production increased by a factor

of four and gas production by a similar amount

(previous page, bottom).

For Petronas, stimulation of oil and ga

production was not the only benefit of the

OneSTEP technique. This simplified acidizing

operation saves significant rig time, resulting in

lower cost. In the Tiong treatment, the

operational time saved was measurable


11/11

conventional treatment was estimated at

45 hours in contrast to 24 hours for the OneSTEP

techniquea 21-hour savings. This time saving

is a direct result of fewer fluid stages and faster

flowback. Other benefits were also realized. Less

equipment and chemical inventory equates to

less deck space required, and fewer chemicals

reduce the operational risks of chemical spills

associated with handling and lifting.

New FieldsSevere Conditions

Great strides have been made in acidizing at high

temperature in the past few years. Treatment with

acid-oil emulsions and chelants allows operators

to acidize formations at elevated temperatures

with reduced corrosion rates and less risk of

secondary damage. As promising as this picture

seems for acidizing, more improvements in

treating agents and procedures will be required to

meet difficult conditions in the future.27

Current world demand for energy is expected

to growit is estimated that 40% more energy

will be required in 2020 than in 2007.

28

As thesearch for new reserves continues, exploration is

turning to deeper reservoirs; operations in the

USA illustrate this trend. In 2007, wells deeper

than 15,000 ft [4,572 m] accounted for about 7%

of domestic production; this is forecasted to grow

to 12% in 2010. The deep gas resource being

produced by this type of well is large and could

be as high as 29% of production in the future.

One defining characteristic of deeper basins

is that they are hot. Deep gas wells in the Gulf of

Mexico and Brazil have average bottomhole

temperatures of 204C [400F], and even higher

temperatures have been reported. To help opera-tors focus on the implications of drilling and

operating deep, hot wells, several classification

systems have been developed.29 Many of these

deep, hot wells will require matrix acidizing at

some point in their life span, and current

technology covers only part of the temperature

range (above left). This trend toward increasingly

higher temperatures will demand improvements

in all aspects of acidizing, from corrosion rates to

treatment-fluid stability.

In spite of the difficulty in acidizing at

extreme conditions, some early successes have

been reported. For example, a South American

high-pressure, high-temperature sandstone well

with significant damage was treated with a

combination of acetic acid and HF, resulting in a

doubling of oil production.30 Keys to success in

this operation at high temperature included a

mild acidaceticassociated with HF, and

inclusion of a phosphonic acid stabilizer to keep

products in solution. Another example of

innovative solutions to acidizing in high-

temperature environments is the use of an in situ

acid system.31 The treatment fluid in this system

contains an acid precursor that delivers time-

controlled release for long-interval wells.

In the final analysis, successful acidizing of

high-pressure, high-temperature wells will place

greater demands on both treatment fluids and

procedures. Fluids will be required that have

controlled reaction rates, low corrosion and

acceptable health, safety and environmental

footprintschelants are a good example of astep in this direction. In addition to the

development of new fluids, treatments like the

OneSTEP technique that emphasize simplicity

and minimize operational time will be at a

premium. Taken together, future developments

in both treating fluids and procedures that

employ them will ensure that matrix acidizing

keeps pace with difficult conditions as new fields

are developed. DA

62 Oilfield Review

> Acidizing deep, hot reservoirs. Acidizing withHCl and HF is typically effective at reservoirtemperatures below 200F, and use of chelantscan extend this temperature range to about

400F. Recent deepwater gas discoveries aregood examples of hot reservoirs and can reachtemperatures of 250 to 550F [288C]. Chelantscould be considered for acidizing fields betweenUrsa at 250F and Egret at 350F, but to acidizefields above 400F, such as West Java, Deep Alexand Mobile Bay, new technology will be required.

HCl-HF

Chelants

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Deep Alex

Mobile Bay

Shearwater

Egret, Heron

E. Cameron, Sable

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Brunei

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Ursa

Gulf of Thailand

Khuff

West Java

100

27. DeBruijn G, Skeates C, Greenaway R, Harrison D,Parris M, James S, Mueller F, Ray S, Riding M,Temple L and Wutherich K: High-Pressure, High-Temperature Technologies, Oilfield Review20, no. 3(Autumn 2008): 4660.

28. Aboud R, Smith K, Forero L and Kalfayan L: EffectiveMatrix-Acidizing in High Temperature Environments,paper SPE 109818, presented at the SPE AnnualTechnical Conference and Exhibition, Anaheim,California, November 1114, 2007.

29. Payne ML, Pattillo PD, Miller RA and Johnston CK:Advanced Technology Solutions for Next GenerationHPHT Wells, paper IPTC 11463, presented at theInternational Petroleum Technology Conference, Dubai,December 47, 2007.

DeBruijn et al, reference 27.

30. Aboud et al, reference 28.

31. Al-Otaibi MB, Al-Moajil AM and Nasr-El-Din HA:In-Situ Acid System to Clean up Drill-In-Fluid Damagein High-Temperature Gas Wells, paper SPE 103846,presented at the IADC/SPE Asia Pacific DrillingTechnology Conference and Exhibition, Bangkok,Thailand, November 1315, 2006.

Documents

Options for High Temperature Well Stimulation