-
4 Oileld Review
Stimulating Naturally Fractured Carbonate Reservoirs
Naturally fractured carbonate reservoirs can be difcult to
stimulate because
treatment uids tend to enter the fractures and avoid less
permeable regions.
Effective uid diversion techniques are usually necessary to
ensure that stimulation
uids contact the largest possible reservoir surface area.
Engineers and chemists
have developed an innovative acidizing uid that employs
degradable bers to
temporarily block permeable fractures and force the uid into
less permeable zones.
Operators have applied the ber-laden acid to naturally fractured
oil and gas reser-
voirs in which achieving complete zonal coverage is difcult and,
as a result, have
witnessed substantial production improvements.
Khalid S. AsiriMohammed A. AtwiSaudi AramcoUdhailiyah, Saudi
Arabia
Oscar Jimnez BuenoPetrleos Mexicanos (PEMEX)Villahermosa,
Mexico
Bruno LecerfAlejandro PeaSugar Land, Texas, USA
Tim LeskoConway, Arkansas, USA
Fred MuellerCollege Station, Texas
Alexandre Z. I. PereiraPetrobrasRio de Janeiro, Brazil
Fernanda Tellez CisnerosVillahermosa, Mexico
Oileld Review Autumn 2013: 25, no. 3. Copyright 2013
Schlumberger.For help in preparation of this article, thanks
toCharles-Edouard Cohen, Rio de Janeiro;Victor Ariel Exler, Maca,
Brazil; Luis Daniel Gigena, Mexico City; Daniel Kalinin, Al-Khobar,
Saudi Arabia; and Svetlana Pavlova, Novosibirsk, Russia.ACTive,
MaxCO3 Acid, POD, SXE and VDA are marks of Schlumberger.
1. Crowe C, Masmonteil J, Touboul E and Thomas R: Trends in
Matrix Acidizing, Oileld Review 4, no. 4 (October 1992): 2440.
2. Robert JA and Rossen WR: Fluid Placement and Pumping
Strategy, in Economides MJ and Nolte KG (eds): Reservoir
Stimulation, 3rd ed. Chichester, West Sussex, England: John Wiley
& Sons, Ltd (2000): 19-219-3.
-
Autumn 2013 55
Since the dawn of the oil and gas industry, opera-tors have
endeavored to maximize well productiv-ity, employing a variety of
techniques to do so. For example, as early as the 19th century,
engineers began pumping acid in wells to improve produc-tion.
Acidizing treatments dissolve and remove formation damage resulting
from drilling and completion operations, create new production
pathways in producing formations or both.
Acidizing treatments fall into two categories. Matrix acidizing
consists of pumping uid into the formation at rates and pressures
that will not fracture the reservoir. The resulting treatment
stimulates a region extending up to about 1 m[3 ft] around the
wellbore. Fracture acidizing is a hydraulic fracturing treatment
that pumps acid during at least one uid stage. The stimulation
distance may extend one or two orders of magni-tude farther into
the formation than that achieved by matrix acidizing.
The composition of acidizing uids depends on the type of
formation to be stimulated. Carbonate formations, composed mainly
of lime-stone (calcium carbonate [CaCO3]) or dolomite (calcium
magnesium carbonate [CaMg(CO3)2]),are treated with hydrochloric
acid [HCl], various organic acids or combinations thereof.
Sandstone formations typically consist of quartz [SiO2] or feldspar
[KAlSi3O8NaAlSi3O8CaAl2Si2O6] par-ticles bound together by
carbonate or clay miner-als. Silicate minerals do not react with
HCl; they respond instead to stimulation uids that contain
hydrouoric acid [HF] or uoboric acid [HBF4].1
Despite the uid chemistry differences, the engi-neering aspects
of carbonate and sandstone acidizing are largely similar. However,
this article concentrates on recent advances that are partic-ularly
relevant to carbonate acidizing.
Carbonate Acidizing FundamentalsLimestone and dolomite rapidly
dissolve in HCl, forming water-soluble reaction productsmainly
calcium and magnesium chloridesand liberating carbon dioxide. The
dissolution rate is limited by the speed at which acid can be
delivered to the rock surface. This dissolution process results in
rapid formation of irregularly shaped channels called wormholes
(above right).Wormholes radiate outward in a dendritic pat-tern
from points where acid leaves the well and enters the formation.
Once formed, they become the most permeable pathways into the
formation and carry virtually all of the uid ow during pro-duction.
For efcient stimulation, the wormhole network should penetrate
deeply and uniformly throughout the producing interval.
Achieving stimulation uniformity can be par-ticularly
challenging when large permeability variations exist within the
treatment interval. As acid penetrates the formation, it ows
preferen-tially into the most-permeable pathways.
Higher-permeability areas receive most of the uid and become
larger, causing the treatment uids to bypass lower-permeability
regions where stimu-lation is needed most. To address this problem,
engineers and chemists have developed methods
to divert acidizing uids away from high-permea-bility intervals
and into less permeable zones.
Engineers accomplish diversion by employing mechanical or
chemical means or both.2
Mechanical diversion of treatment uids may be achieved using
drillpipe or coiled tubingcon-veyed tools equipped with mechanical
packers that isolate and direct uid into low-permeability zones.
Alternatively, ow can be blocked at indi-vidual perforations by
dropping ball sealers into
> Acid-induced wormholes. An intricate network of wormholes
formed during a laboratory-scale matrix acidizing treatment of a
carbonate formation sample. The length, direction and number of
wormholes depend on the formation reactivity and the rate at which
acid enters the formation. Once formed, the wormholes may carry
virtually all of the uid ow during production.
-
6 Oileld Review
the stimulation uid as it travels down the well.The ball sealers
are drawn to and seat againstperforations accepting the most uid.
After thetreatment, the ball sealers fall away, are mechan-ically
dislodged or dissolve (above).
Chemical diverting agents incorporated instimulation uids may be
divided into two catego-riesparticulates and viscosiers.
Particulatesinclude plugging agents such as benzoic acidakes and
salt grains that are sized to plug forma-tion pores. Foaming the
acid may achieve a simi-lar plugging effect because of two-phase
ow.
Viscosiers include water-soluble polymers,crosslinked polymer
gels and viscoelastic surfac-tants (VESs).3 A decade ago,
Schlumberger scien-tists and engineers applied VES chemistry to
acidstimulation and introduced the VDA viscoelastic
diverting acid system. VDA uids have been par-ticularly
successful in both matrix and fractureacidizing applications around
the world.4
The surfactant molecule in the VDA system,derived from a
long-chain fatty acid, is zwitter-ionica neutral molecule that
carries a positiveand a negative charge at separate positions.5
While being pumped down a well, VDA uidablend of HCl, VES and
common acid-treatmentadditivesmaintains a low viscosity. As the
acidis consumed in the formation, the surfactant mol-ecules begin
to aggregate into elongatedmicelles.6 The micelles become entangled
andcause the uid viscosity to increase (below). Thehigher-viscosity
uid forms a temporary barrierthat forces fresh acid to ow
elsewhere. In addi-tion to providing diversion, the viscosity
decreases
the rate at which the acid reacts with the forma-tion, thereby
allowing more time for the creationof deeper and more intricate
wormholes.
When production begins, VDA uid is exposedto hydrocarbons, which
alters the ionic environ-ment and causes the micelles to become
spheri-cal. Entanglement ceases, the micelles roamfreely, and the
uid viscosity decreases dramati-cally, enabling efcient
poststimulation cleanup.Unlike polymer-base uids, VESs leave
virtuallyno damaging residue behind that may interferewith well
productivity.
Naturally fractured reservoirs are the mostchallenging
environments for carbonate acidiz-ing because they can present
extreme permeabil-ity contrasts. The fractured regions may
beseveral orders of magnitude more permeablethan the unfractured
layers. Until recently, theindustrys considerable portfolio of
diversiontechnologies has been inefcient in this environ-ment. Even
when using self-diverting uids suchas the VDA formulation,
engineers struggled toblock the fractures and treat the rest of the
for-mation. Consequently, operators were forced topump large
volumes of uid to achieve stimula-tion, leading to higher treatment
costs and lessthan optimal results.
However, Schlumberger engineers and chem-ists discovered that
signicant diversion improve-ments could be achieved by adding
degradablebers to VDA uid. As ber-laden diversion uidenters a
fracture, the bers congregate, entangleand form structures that
limit uid entry. Thenew product, MaxCO3 Acid degradable
diversionacid system, has been used successfully and ef-ciently to
stimulate notoriously difcult carbon-ate reservoirs around the
world.
>Mechanical diversion methods. Ball sealers (green spheres)
are pumped down the well during thestimulation treatment (left).
The balls provide mechanical diversion because they preferentially
blockthe perforations that take the highest volume of treatment
uid. Straddle packers may also be deployedon coiled tubing to
isolate the preferred treatment interval (right). In this example,
engineers havealready stimulated the bottom zone and moved the
packers up in preparation for stimulating the next zone.
Ball Sealers Straddle Packers
> Viscoelastic surfactant (VES) uid behavior during an
acidizing treatment. Initially, when the surfactant is dispersed in
acid, each molecule movesindependently throughout the uid (left).
As the acid reacts with the carbonate minerals, the surfactant
molecules assemble and create elongated micelles(center). The
micelles entangle and hinder uid ow, resulting in higher uid
viscosity. When hydrocarbon production begins after the treatment,
theelongated micelles transform into spheres (right), resulting in
a dramatic decrease in uid viscosity and facilitating efcient
cleanup.
Surfactantmolecules
Elongated micelles Spherical micelles
Spent acid Hydrocarbon
CaCO3 + 2HCl CaCl2 + CO2 + H2O
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Autumn 2013 7
This article describes the development of theMaxCO3 Acid system
in the laboratory and itsintroduction to the oil eld. Case
histories fromMexico, Saudi Arabia and Brazil demonstratehow
application of this new acid system is achiev-ing signicant well
productivity improvements.
Studying Fiber-Laden Acids in the LaboratoryFor more than 20
years, chemists and engineershave explored ways in which bers could
be usedto improve well servicing operations. Working
with both mineral- and polymer-base bers, theydiscovered
techniques for controlling the behav-ior of uids and suspended
solids, both duringand after placement in a well. The
researchresulted in several innovations, including meth-ods for
limiting lost circulation during drillingand cementing, improving
the exibility anddurability of well cements, aiding proppant
trans-port during hydraulic fracturing operations andpreventing
proppant owback into the well aftera fracturing treatment.
Studying applications for bers in the contextof acidizing has
been a more recent endeavor. In2007, scientists at Schlumberger
began exploringthe ability of bers to improve uid diversion inboth
openhole and cased hole scenarios (above).The principal difference
between the two condi-tions is that, for openhole completions,
bersmust accumulate along the entire wellbore sur-face to provide
diversion, but in a cased holesituation, ber deposition may be
conned toperforations.
The engineers discovered that simply addingbers to a
conventional HCl solution failed to cre-ate a stable brous
suspension. Shortly afteraddition, the bers congregated, formed
clumpsand separated from the acid. Success wasachieved by adding
bers to VDA uid. The resul-tant higher uid viscosity allowed the
creation ofa robust suspension of discrete bers.
3. For more on water-soluble polymers and VESs: Gulbis Jand
Hodge RM: Fracturing Fluid Chemistry andProppants, in Economides MJ
and Nolte KG (eds):Reservoir Stimulation, 3rd ed. Chichester, West
Sussex,England: John Wiley & Sons, Ltd (2000): 7-17-23.
4. Al-Anzi E, Al-Mutawa M, Al-Habib N, Al-Mumen A,Nasr-El-Din H,
Alvarado O, Brady M, Davies S, Fredd C,Fu D, Lungwitz B, Chang F,
Huidobro E, Jemmali M,Samuel M and Sandhu D: Positive Reactions
inCarbonate Reservoir Stimulation, Oileld Review 15,no. 4 (Winter
2003/2004): 2845.Lungwitz B, Fredd C, Brady M, Miller M, Ali S
andHughes K: Diversion and Cleanup Studies of Viscoelastic
> Fiber deposition and diversion scenarios. During openhole
acidizing (top and bottom left), bers forma ltercake that covers
the entire wellbore wall. During cased hole acidizing (top and
bottom right),bers form ltercakes in the perforation tunnels.
Wellborewall
Openhole Acidizing Cased Hole Acidizing
Well Well
Casing
Filtercake
Filtercake
FiltercakeTreatment fluid Treatment fluid
Filtercake
Wormhole
Wormhole Perforation
Perforation
Casing
Surfactant-Based Self-Diverting Acid, SPE Production
&Operations 22, no. 1 (February 2007): 121127.
5. Sullivan P, Nelson EB, Anderson V and Hughes T:
OileldApplications of Giant Micelles, in Zana R and Kaler EW(eds):
Giant MicellesProperties and Applications.Boca Raton, Florida, USA:
CRC Press (2007): 453472.
6. A micelle is a colloidal assembly of surfactant molecules.In
the aqueous environment of an acidizing uid, thesurfactant
molecules are arranged such that the interiorof the micelle is
hydrophobic and the exterior ishydrophilic. Worm-like micelles may
be microns long andhave a cross section of a few nanometers.
-
8 Oileld Review
The engineers then began performing exper-iments with
laboratory-scale equipment forsimulating uid leakoff and ber
deposition(above). The principal simulator was a bridgingapparatus
that accommodated a variety of ori-ces through which ber-laden acid
could passat various ow rates. Circular orices, withdiameters
between 1 and 2 mm [0.04 and0.08 in.], simulated wormholes.
Rectangular ori-ces with widths between 2 and 6 mm [0.08 and0.24
in.] were analogous to fractures. Engineersobserved ber plug
formation and recorded thecorresponding system pressure as
ber-ladenacid passed through an orice.
> Laboratory-scale equipment for testing leakoff behavior and
ltercake deposition. Engineers used a conventional ltration cell to
simulate an openholestimulation (top). Technicians rst placed a
carbonate core at the bottom of the cell and then poured in
ber-laden acid. After sealing the cell, they applieddifferential
pressure across the core and used a balance to measure the amount
of ltrate passing though the core. For the cased hole simulation
(bottom),engineers used a bridging apparatus. The apparatus
consisted mainly of a 300-mL tube tted with a piston, a
high-performance liquid chromatography(HPLC) pump and an orice
(left). The orice could be circular to simulate a wormhole (top
right) or rectangular to mimic a fracture (bottom
right).Technicians installed a piston at the top of the tube, which
contained ber-laden acid. Acid exiting the tube passed through the
orice, and the techniciansassessed the diversion capability of bers
by measuring the ltrate volume, the ber ltercake volume and the
pumping pressure at various ow rates.
Pressure
Filtercake
Filtrate
Balance
Pressure cell
Acid andfibers
Backpressureregulator
Core
Openhole Simulation
Flui
d flo
w
130 mm
ID 21 mm
20 mm1 to 2 mm
2 to 6 mm
25.75 mm
65 mm
75 mm
Piston
FiltercakeOrifice
Orifice
Orifice
Pressure sensor14
2 cm
Pump
Wormhole Geometry
Fissure or Fracture Geometry
Acidand fibers
Cased Hole Simulation
Pressure evolution in the apparatus followeda consistent pattern
(next page, top left).Initially there was no pressure increase,
butwithin a few seconds, the pressure rose rapidlyas the bers
formed a bridge and began to llthe orice. These results indicated
that as earlyvolumes of ber-laden acid reach the perfora-tions, the
acid penetrates the reservoir as if nobers are present. Then, as
the bers bridge,they accumulate inside the perforations andform a
ltercake. Next, the bers plug theperforation, decreasing
injectivity and promot-ing uid diversion into other
perforations.The engineers also discovered that the ber
concentration required to achieve bridgingincreased with the uid
injection rate (nextpage, top right).
In the laboratory, after pumping the ber-laden acid through the
orice, engineers per-formed a freshwater ush. As the viscous
acidleft the apparatus, the pumping pressure gradu-ally decreased
and eventually stabilized. At theend of each test, a stable ber
plug remained inthe orice. Knowing the pressure, ow rate,uid
viscosity and ber plug length, engineerswere also able to use
Darcys law to calculatethe ber plug permeabilities. Depending on
theber concentration and the uid ow rate dur-
-
Autumn 2013 9
7. It may appear counterintuitive to imagine that ber plugswith
permeabilities higher than that of the formationcould provide
signicant diversion. However, signicantdiversion is also provided
by the ow restriction andpressure drop as uid enters the
perforations.
8. Cohen CE, Tardy PMJ, Lesko T, Lecerf B, Pavlova S,Voropaev S
and Mchaweh A: Understanding Diversionwith a Novel Fiber-Laden Acid
System for MatrixAcidizing of Carbonate Formations, paper SPE
134495,presented at the SPE Annual Technical Conference
andExhibition, Florence, Italy, September 1922, 2010.
> Pressure-versus-time plot from a slot-ow experiment. During
thisexperiment, the MaxCO3 Acid composition consisted of 15 wt% VDA
uid and6 kg/m3 (50 lbm/1,000 galUS) degradable bers. In Period 0,
MaxCO3 Acid uidbegins owing through the slot, and the bers have not
yet formed a bridge.In Period 1, the pressure rises as the bers
entangle and form a plug in theslot. Pressure continues to climb
until the volume of acid is exhausted. InPeriod 2, the pressure
gradually falls as freshwater enters the slot anddisplaces the
viscous acid. The system pressure stabilizes during Period 3.The
white ber plug remains intact and stable inside the slot
(photograph).
Pres
sure
, psi
40
50
60
30
0 1 2 3
20
10
0 10 20 30
Time, s40 50 60 70 80
0
2-mmslot
Fluid inflow
ing ber deposition, the measured permeabili-ties varied between
400 and 2,400 mD. Thesedata led engineers to conclude that bers
wouldprovide the most efcient diversion in zoneswith permeabilities
exceeding 100 mD (left).7
The data acquired during the simulator exper-iments also allowed
scientists to develop a math-ematical model for predicting the
behavior ofber-laden acids under openhole and cased holeconditions;
the model may be used to optimizetreatment designs.8 They performed
340 ne-scale3D simulations that evaluated typical
perforationschemes, brous ltercake permeabilities andformation
permeabilities. The resulting modelallows scientists to track the
movement of the u-ids and bers through the wellbore and into
thereservoir and track the propagation of wormholesgenerated as the
acid reacts with carbonate rock.
> Effect of degradable ber concentration onbridging ability
in a slot. During the slot-owexperiments, engineers determined that
the berconcentration required to achieve bridging andpromote uid
diversion increases with the uidinjection rate.
Linear fluid velocity, m/min
Linear fluid velocity, ft/min
30251550 2010
32.8 49.2 65.6 82.0 98.416.40
50
100
150
Degr
adab
le fi
ber c
once
ntra
tion,
lbm
/1,0
00 g
alUS
Bridging region
Nonbridging region
> Apparent permeability resulting from plugging a perforated
zone withbers. The x-axis shows the original core permeability. The
y-axis shows theapparent zone permeability after a brous ltercake
with a permeability of2 D has formed. The results show that after
plugging occurs, when corepermeability exceeds about 1 mD, apparent
permeability eventually levels offat about 100 mD and becomes
independent of core permeability.
Appa
rent
per
mea
bilit
y, m
D
0.10.1
1
1
10
10
100
100
10,000
10,000
1,000
1,000
Core permeability, mD
-
10 Oileld Review
> Diversion predictions from the MaxCO3 Acid simulator.
During ber deposition experiments in the perforation simulator, the
permeabilities of the resultingber plugs varied between about 400
and 2,400 mD (left). The simulator predicts how the ber plugs
decrease the apparent permeabilities of reservoirs andpromote
diversion. Lower-permeability ber plugs are more efcient diverters.
Modeling studies also demonstrated that brous ltercakes provide
uiddiversion by equalizing the permeabilities of layers in the
treated interval. For example, if the interval contains four layers
with various permeabilities, theuid ow rate into the more permeable
layers decreases and the uid ow rate into the less permeable layers
increases. Eventually, the ow ratesconverge to a single ow rate,
and the interval behaves as if it has a single permeability
(right). Flow rate convergence occurs more quickly in a cased
holewith perforations because the ltercake surface area is
lower.
Appa
rent
rese
rvoi
r per
mea
bilit
y, m
D
Reservoir permeability, mD0.1
0.11
1
10
10
100
100
10,000
10,000
1,000
1,000
Fiber plug permeability2,400 mD1,500 mD400 mD
Layer permeability30 D10 D3 D1 D
Time
Flow
rate
>MaxCO3 Acid uid batch mixing. The degradable bers (top left)
are light and nely divided, presenting a mixing challenge.
Traditional equipment forbatch mixing of acidizing uids was
inefcient. Engineers discovered that equipment for batch mixing
cement slurries (bottom left) could disperse the bersin VDA uid.
The VDA uid ows into an 8,000-L [50-bbl] paddle mixer (top right).
To avoid the formation of clumps, eld personnel manually add bers
to theuid. After the bers have been added, the tank is lled with
more VDA uid, and agitation continues until the mixture reaches a
uniform consistency(bottom right). During the job, engineers
maintain the agitation to preserve uid uniformity.
-
Autumn 2013 11
9. For more on formation damage testing in the laboratory:Hill
DG, Litard OM, Piot BM and King GE: FormationDamage: Origin,
Diagnosis and Treatment Strategy, inEconomides MJ and Nolte KE
(eds): ReservoirStimulation, 3rd ed. Chichester, West Sussex,
England:John Wiley & Sons, Ltd (2000): 14-3114-33.
> Behavior of degradable bers. Engineers performed static
bottle tests during which degradablebers were immersed in partially
spent HCl uids. The data show that the rate of ber
dissolutiondecreases as the HCl becomes neutralized. Nevertheless,
complete ber dissolution occurs within afew days (top). Core
testing demonstrated that the acidic ber degradation products may
furtherstimulate the formation (bottom). Using a standard core
testing apparatus at 115C [239F], engineerspumped 2% KCl solution
into a limestone core rst in the injection direction and then in
the reverse, orproduction, direction (K0 and K1). Technicians
recorded the pressure across the core and, applyingDarcys law,
determined that the initial core permeability was 5.1 mD. Next,
they injected a partiallyspent 20% HCl uid (pH = 6.5) containing
degradable bers (N2). Subsequent pumping of 2% KCl in
bothdirections revealed that the core permeability had fallen to
3.5 mD (K2 and K3). Following a 16-h shut-inperiod, the bers had
begun to degrade, and the core permeability rose to about 4.8 mD
(K4 and K5).After another 16-h shut-in period, complete ber
degradation had occurred, and the core permeabilityrose to 5.5 mD
(K6 and K7)an 8% improvement over the initial permeability of 5.1
mD.
Fibe
r deg
rada
tion
time,
hVolume of acid spent at 100C, %
20
20 30 40 50 60 70 80 90 100100
40
60
80
100
120
0Pe
rmea
bilit
y, m
D
Fluid volume, pore volumes
2% KCI (injection direction)2% KCI (production direction)Fibers
injected with spent acid (pH = 6.5)
16-hshut-in
K0 K1
K2K3
K4K5
K6K7
N2
16-hshut-in
10
9
8
7
6
5
4
3
2
1
00 5 10 15 20 25 35 45 50 5530 40
In addition, the model predicts uid diversionbehavior (previous
page, top).
After demonstrating the diversion capabili-ties of ber-laden VDA
uids in the laboratory,the developers considered the effects of
bers onreservoir productivity following an acidizingtreatment. If
bers remained in the wormholesindenitely, their presence would
hinder the owof uids from the reservoir to the wellbore. Forthis
reason, degradable bers were viewed as anattractive option. After a
treatment, the bershydrolyze and degrade within a few days.
Theabsence of bers leaves unobstructed wormholesand maximizes
formation productivity. Further-more, the degradable bers are
composed of anorganic acid polymer whose degradation prod-ucts are
acidic, giving rise to further formationstimulation (right).9
The results of the laboratory study were suf-ciently encouraging
to allow the engineers toadvance to the next development
stageyardtesting to demonstrate that the ber-ladenMaxCO3 Acid uid
could be prepared and pumpedefciently and safely.
Verifying Wellsite DeliverabilityBecause matrix acidizing
treatments typicallyconsume small uid volumes compared withother
stimulation techniques, engineers usuallyemploy batch-mixing
procedures. By contrast,fracture acidizing usually requires large
uid vol-umes, and continuous mixing is necessary tokeep pace with
the higher pump rates.Consequently, engineers needed to
developmethods for mixing MaxCO3 Acid formulations inboth
scenarios. The principal objectives were todisperse the bers safely
and efciently in theuid and prepare a uniform suspension.
Becausethe degradable bers are light and nely divided,engineers
were challenged to devise ways toimmerse the bers in the VDA uid so
that theywould form a homogeneous mixture.
Experimentation led to the discovery thatuniform MaxCO3 Acid
mixtures can be efcientlybatch mixed with existing equipment
(previouspage, bottom). The equipment consists of a ves-sel, into
which engineers pour the base VDA uid,and an 8,000-L [50-bbl]
recirculating mixing tankequipped with rotating paddles. Field
personneldispense the bers manually. Until the treatmentcommences,
continuous agitation prevents berand uid separation.
The POD programmable optimum densityblender is standard
Schlumberger equipment forcontinuously dispensing solid materials
such asproppant into fracturing uids, and it proved to
be an efcient system for preparing MaxCO3 Acidmixtures. However,
the uid exit points must besecure to ensure that personnel are
shieldedagainst uid leaks and sprays. Therefore, engi-neers
designed a special splash protection kit
-
12 Oileld Review
10. Bullheading is the pumping of uids into a wellbore fromthe
surface with no direct control over which intervalswill accept the
uids.
11. Thabet S, Brady M, Parsons C, Byrne S, Voropaev S,Lesko T,
Tardy P, Cohen C and Mchaweh A: Changingthe Game in the Stimulation
of Thick Carbonate GasReservoirs, paper IPTC 13097, presented at
theInternational Petroleum Technology Conference,Doha, Qatar,
December 79, 2009.
that includes a berm below the blender and aplastic sidewall
(above left). They also developeda special chute for metering the
degradablebers as they are dispersed into the mixing tub.The modied
chute, mounted directly above themixing tub, has no restrictions or
bends thatmight hinder smooth ber delivery.
After verifying that MaxCO3 Acid uids couldbe prepared reliably
with existing eld equip-ment, the project team traveled to Qatar
foreld testing. A principal test objective was toevaluate the
accuracy of the acid placement anddiversion simulator.
Field Testing in QatarThe North eld in Qatar is an offshore gas
pro-ducer that presents unique challenges for com-pletion and
stimulation (above right). Thereservoir is 1,000 to 1,300 ft [300
to 400 m] thickand the wells, which may be deviated by as muchas
55, can be as long as 2,000 ft [610 m]. The res-ervoir comprises
alternating sequences of lime-
> Continuous mixing of MaxCO3 Acid uid. A POD blender is
outtted with aspecial ber delivery feeder (top right) that has no
restrictions or bends,thus ensuring smooth metering. Field workers
place a berm (top left) underthe blender to guard against uid
spills. A plastic sidewall around the mixingtubs (bottom) further
shields the mixing process.
Fiber feeder
> Qatar North eld. Discovered in the 1970s, this accumulation
is the largestgas eld in the world, with estimated reserves as high
as 25.5 trillion m3[900 Tcf]. The reservoir is called the South
Pars eld on the Iranian side ofthe maritime border (dashed black
line). The producing formation ischaracterized by large interzonal
permeability contrastsup to a ratio of100:1. The reservoir depth is
about 3,000 m [9,800 ft] below the seabed, andthe elevated
hydrostatic pressure tends to favor stimulation of bottomzones at
the expense of upper reservoir layers, further increasing
thedifculty of achieving uniform stimulation in one treatment.
IRAN
QATAR
BAHRAINNorthField
SouthPars
SAUDIARABIA
0 km
0 mi 50
50
SAUDIARABIA
IRAN
> Jujo-Tecominoacn eld. This region is among the most prolic
oil and gas producing areas insouthern Mexico. The reservoirs are
naturally fractured and difcult to stimulate uniformly.
Villahermosa
TabascoState
Jujo-Tecominoacn Field
50
km0 50
miles0
UNITED STATES
MEXICO
-
Autumn 2013 13
stone and dolomite that have a permeabilitycontrast ratio as
high as 100:1.
The typical workow for designing and per-forming a MaxCO3 Acid
treatment consisted ofseveral steps. To build a reservoir model,
engi-neers rst acquired a thorough description of thecandidate
well. The description included wellcompletion diagrams,
petrophysical and pressurelog measurements and pretreatment well
pro-duction data. The simulator produced a pumpingschedule designed
to provide optimal zonal cov-erage and maximize posttreatment
reservoir per-meability. During the treatment, engineersmeasured
the bottomhole and wellhead pres-sures and compared the results
with those pre-dicted by the simulator. Posttreatment
activitiesincluded production logging to further verify theaccuracy
of the simulator.
One test well had 290 ft [88 m] of perforationsalong 830 ft [250
m] of measured depthbetween 12,270 and 13,100 ft [3,740 and 3,990
m].The principal obstacles to effective acid place-ment were the
high permeability contrast andhydrostatic pressure effects favoring
preferentialstimulation of deeper high-permeability zones(right).
Prior to these eld tests, installation ofbridge plugs had been the
preferred technique toachieve uid diversion.
Schlumberger engineers performed a matrixacidizing treatment
from a stimulation vesselusing the bullheading technique.10 The
treatmentconsisted of alternating stages of 290 bbl [46 m3]of 28%
HCl and 320 bbl [51 m3] of MaxCO3 Aciduid containing 75 lbm/1,000
galUS [9.0 kg/m3]of degradable bers. To ensure uniform ber
sus-pension, engineers set up the treatment so that160-bbl [25-m3]
spacers of VDA uid precededand followed the MaxCO3 Acid stages.
During thetreatment, the simulated and measured bottom-hole
pressures were in good agreement, provid-ing conrmation that the
diversion physics ofMaxCO3 Acid behavior were well described by
thesimulator (right).
After the success of the rst test well, engi-neers performed 10
more acidizing treatments inthe eld with similar results.11 The
ber-ladenacid performed as predicted, and operationalefciencies
were gained by not having to rely onmechanical diversion. The time
required to com-plete, perforate, stimulate and clean up theMaxCO3
Acid wells was two to four days shorterthan that of the traditional
approach, represent-ing a savings of US$ 480,000 to US$ 960,000
perwell. Environmental benets included a 72%reduction in the
emission of greenhouse gasesbecause of reduced aring. Following the
successof the Qatari eld tests, the operator deployedMaxCO3 Acid
technology in other regions.
> Permeability prole. The permeability varies four orders of
magnitude in atest well in the Qatar North eld.
Mea
sure
d de
pth,
ft
Permeability, mD
13,2000.1 1 10 100 1,000
13,100
13,000
12,900
12,800
12,700
12,600
12,500
12,400
12,300
12,200
> Simulated and measured pressures from a eld test in the
Qatar North eld. Engineers pumped fourstages of 28% HCl and MaxCO3
Acid uid. A VDA uid spacer preceded and followed each MaxCO3Acid
stage to preserve ber suspension uniformity. The excellent
agreement between the measured(blue curve) and simulated (black)
bottomhole pressures (BHP) helped conrm the validity of theMaxCO3
Acid placement model.
6,500
7,500
6,000
7,000
8,000
5,500
5,00080 100 120 140 160
25
35
30
40
20
15
10
50
BHP,
psi
Time, min
Pum
p ra
te, b
bl/m
in
Measured BHPSimulated BHPPump rate
Fluid at perforationsMaxCO3 Acid fluidWater
GasHCIVDA acid
Optimizing Production in Southern MexicoThe Jujo-Tecominoacn
eld, operated byPetrleos Mexicanos (PEMEX), is located 60 km[40 mi]
from Villahermosa, Tabasco, in southern
Mexico (previous page, bottom). The eld has48 producing wells
and 19 injection wells tomaintain reservoir pressure. The average
depthof the producing intervals is 5,000 m [16,400 ft],
-
14 Oileld Review
and the reservoir temperature varies between120C and 160C [250F
and 320F]. Wells in thiseld typically produce from multiple
perforatedintervals with a highly variable natural fracturedensity.
This scenario creates a large permeabil-ity contrast between
intervals that can reach1,000:1. Consequently, achieving uniform
zonal
coverage during stimulation treatment presentsa major
challenge.
One typical well that was drilled in 2005 hastwo producing
intervals: from 5,274 to 5,294 m[17,303 to 17,369 ft] and from
5,308 to 5,340 m[17,415 to 17,520 ft]. The reservoir temperatureand
pressure are 137C [279F] and 22.8 MPa
[3,300 psi]. Porosity varies between 5% and 8%.The
permeabilities of the upper and lower inter-vals are 1,000 mD and 3
mD; therefore, the per-meability contrast is 333:1.
The initial oil production rate was 1,278 bbl/d[203 m3/d].
Between 2006 and 2009, PEMEX per-formed several stimulation
treatments using con-ventional acids and diversion techniques.
Theproduction rate increased immediately aftereach treatment but
failed to stabilize and contin-ued to decline. In 2009, PEMEX
engineersdecided to evaluate the MaxCO3 Acid technologyin the hope
of achieving uniform and long-lastingstimulation of the two
intervals.12
Schlumberger engineers performed a matrixacidizing treatment
consisting of bullheading30 m3 [7,800 galUS] of aromatic solvent
preush toclean the perforations, 60 m3 [15,600 galUS] ofHClformic
acid blend, 10 m3 [2,600 galUS] ofMaxCO3 Acid uid containing 90
lbm/1,000 galUS[11 kg/m3] bers and 2 m3 [520 galUS] of ammo-nium
chloride brine spacer (above left). Pumprates varied between 8.2
and 15 bbl/min [1.3 and2.4 m3/min]. The last treatment stage
containednitrogen to energize the uid and accelerate wellcleanup,
and hydrocarbon production commencedwithin three days. The initial
oil production rate,3,000 bbl/d [480 m3/d], exceeded PEMEXs
fore-cast. After three months, the average oil produc-tion rate had
stabilized at 1,600 bbl/d [250 m3/d](below left). Following the
success of this treatment,PEMEX has continued to apply MaxCO3 Acid
tech-nology in this eld with favorable results.
> Pumping schedule for a matrix acidizing treatment in the
Jujo-Tecominoacn eld. During the 11-stage treatment, engineers
pumped anaromatic solvent to clean up perforations, an HClformic
acid blend,MaxCO3 Acid uid and an ammonium chloride brine spacer.
The nal stagecontained nitrogen [N2] to enhance well cleanup.
Fluid NameStage Name Stage FluidVolume, m3Nitrogen Pump
Rate, m3/min
Spacer 3% NH4Cl brine
Spacer 3% NH4Cl brine
Diverter MaxCO3 Acid fluid
Diverter MaxCO3 Acid fluid
Acid HCIformic acid blend
HCIformic acid blend
HCIformic acid blend
Acid
Preflush Aromatic solvent
Preflush Aromatic solvent
Preflush Aromatic solvent
Acid
1
1
5
5
20
20
10
10
10
20
Flush Nitrogen
80
80
150
> Production history in a PEMEX well in the Jujo-Tecominoacn
eld. Initial oil production was1,278 bbl/d [203 m3/d]. Subsequent
matrix acidizing treatments employing conventional techniquesfailed
to achieve sustained production improvements. After a MaxCO3 Acid
treatment in December2009, oil production increased to 3,000 bbl/d
and stabilized at 1,600 bbl/d, exceeding the originalproduction
rate.
Oil p
rodu
ctio
n ra
te, b
bl/d
Date
Begin MaxCO3 Acid treatment
Oil production
Jan 2009 Jan 2010Apr 2009 Apr 2010July 2009 Oct 2009
2,000
2,500
3,000
3,500
1,500
1,000
500
0
12. Martin F, Quevedo M, Tellez F, Garcia A, Resendiz T,Jimenez
Bueno O and Ramirez G: Fiber-AssistedSelf-Diverting Acid Brings a
New Perspective to Hot,Deep Carbonate Reservoir Stimulation in
Mexico,paper SPE 138910, presented at the SPE Latin Americanand
Caribbean Petroleum Engineering Conference,Lima, Peru, December 13,
2010.
13. Rahim Z, Al-Anazi HA, Al-Kanaan AA and Aziz AAA:Successful
Exploitation of the Khuff-B Low PermeabilityGas Condensate
Reservoir Through OptimizedDevelopment Strategy, Saudi Aramco
Journal ofTechnology (Winter 2010): 2633.
14. Aviles I, Baihly J and Liu GH: Multistage Stimulationin
Liquid-Rich Unconventional Formations,Oileld Review 25, no. 2
(Summer 2013): 2633.
15. Jauregui JL, Malik AR, Solares JR, Nunez Garcia W,Bukovac T,
Sinosic B and Grmen MN: SuccessfulApplication of Novel Fiber Laden
Self-Diverting AcidSystem During Fracturing Operations of
NaturallyFractured Carbonates in Saudi Arabia, paperSPE 142512,
presented at the SPE Middle East Oil andGas Show and Conference,
Manama, Bahrain,September 2528, 2011.
-
Autumn 2013 15
> South Ghawar eld in eastern Saudi Arabia. The producing
reservoirs, in the Khuff Formation, arecomposed of heterogeneous
carbonates. The permeability and porosity vary widely within 100 to
200 ft[30 to 60 m] of formation thickness, presenting difcult uid
diversion challenges.
IRAN
BAHRAIN
QATAR
UNITED ARABEMIRATES
SAUDI ARABIA
South Ghawar Field
0 km
0 mi 100
100
GasOil
SAUDIARABIA
EGYPT
IRAN
Improving Gas Production in Saudi ArabiaThe vast carbonate
reservoirs of Saudi Arabia areprime locations for stimulation
treatments usingacidic uid systems. From simple acid washes tomajor
acid fracturing operations, every carbon-ate stimulation technology
has found an applica-tion in this region.
Most gas production in Saudi Arabia comesfrom the Khuff
Formation, located in the easternpart of the country (right). The
Khuff Formationis highly heterogeneous, exhibiting wide varia-tions
in formation permeability (0.5 mD to10 mD) and porosity (5% to
15%). It is composedmainly of calcite and dolomite interbedded
withstreaks of anhydrite. The average temperatureand pressure are
280F [138C] and 7,500 psi[52 MPa].13
Saudi Aramco engineers applied MaxCO3 Acidtechnology during
several matrix acidizingtreatments, all of which yielded
excellentresults. Following this success, Saudi Aramcoengineers
decided to perform 25 acid fracturingtreatments employing the
MaxCO3 Acid formu-lation. Eight acid fracturing stages were
per-formed in three wells equipped with openholemultistage
fracturing completions that enabledcontinuous treatments.14 The
remainder of thejobs, single-stage treatments in vertical or
devi-ated wells, were completed with cemented andperforated
liners.15
Engineers performed one treatment in acemented and perforated
well that had a 65deviation. Three pay zones existed along a
240-ft[73-m] interval in the central sector of the eld.From
reservoir parameters obtained from open-hole logs, engineers
concluded that, to meetSaudi Aramcos production expectations, it
wouldbe necessary to pump a treatment that stimu-lated all three
perforated zones simultaneously.
Engineers developed a fracturing treatmentthat consisted of 19
uid stages that alternatedportions of a 35-lbm/1,000 galUS
[4.2-kg/m3]borate crosslinked guar fracturing uid, 28% SXEsuperX
emulsied acid to retard the rate of acidconsumption, 28% HCl and
15% MaxCO3 Acid for-mulation with degradable ber
concentrationsbetween 75 and 175 lbm/1,000 galUS [9 and21 kg/m3]
(right). During the treatment, after therst MaxCO3 Acid stage
contacted the formation,engineers recorded a 4,500-psi [31-MPa]
bottom-hole pressure risethe rst time such a largeincrease had been
recorded in this carbonatereservoirindicating that excellent uid
leakoff > Pumping schedule for an acid fracturing treatment in
Saudi Arabia. The total uid volume was
124,200 galUS [2,960 bbl, 470 m3], allowing simultaneous
stimulation of three zones without the need formechanical diversion
techniques. Such treatment simplicity saved several days of rig
time, resulting insignicant operational cost savings.
Treatment Schedule
Fluid NameStage Name Stage FluidVolume, galUS [m3]Acid
Concentration, %Pump Rate,
bbl/min [m3/min]
20 [3.2]
30 [4.8]
40 [6.4]
40 [6.4]
40 [6.4]
30 [4.8]
35 [5.6]
30 [4.8]
35 [5.6]
40 [6.4]
20 [3.2]
30 [4.8]
40 [6.4]
40 [6.4]
10 [1.6]
10 [1.6]
10 [1.6]
10 [1.6]
40 [6.4]
0
0
0
0
0
0
0
15
15
15
28
28
28
28
0
0
15
28
0
Pad
Pad
Pad
Pad
Pad
Pad
Pad
Diverter 1
Diverter 2
Diverter 3
Acid 1
Acid 2
Acid 3
Acid 3
Overflush 2
Flush
Diverter 4
Acid 4
Overflush 1
Crosslinked 35-lbm gel
Crosslinked 35-lbm gel
Crosslinked 35-lbm gel
Crosslinked 35-lbm gel
Crosslinked 35-lbm gel
Crosslinked 35-lbm gel
Crosslinked 35-lbm gel
MaxCO3 Acid fluid
MaxCO3 Acid fluid
MaxCO3 Acid fluid
SXE emulsified acid
SXE emulsified acid
SXE emulsified acid
SXE emulsified acid
Overflush
Water
MaxCO3 Acid fluid
28% HCl
Overflush
9,000 [34]
9,000 [34]
9,000 [34]
3,000 [11]
10,000 [38]
3,000 [11]
3,000 [11]
3,000 [11]
3,000 [11]
9,000 [34]
9,000 [34]
9,000 [34]
9,000 [34]
5,000 [19]
11,200 [42]
3,000 [11]
7,000 [26]
7,000 [26]
3,000 [11]
-
16 Oileld Review
> Pressure and temperature data. During a Saudi Aramco acid
fracturing treatment, the pumping rate(blue line) varied from 10 to
40 bbl/min [1.6 to 6.4 m3/min], and the bottomhole treating
pressure (redline) exceeded the formation fracturing pressure
(dashed black line) throughout most of the treatment.The vertical
blue bars denote periods during which MaxCO3 Acid uid entered the
perforations.
8,000
6,600
5,200
3,800
2,400
1,000
10
10 30 50 70 90 110 130 150 170
25
40
55
70
85
100
115
9,400
10,800
12,200
15,000
13,600
Pres
sure
, psi
Treatment time, min
Fracturing pressure
Rate
, bbl
/min
10
1Bottomhole treating pressurePump rate
> The presalt reservoirs of Brazil. The main producing elds
are located primarily offshore (left). The reservoirs are in
carbonate formations that lieunderneath a thick layer of evaporite
minerals (right). The reservoir depth is between 4,500 and 6,500 m
[14,800 and 21,300 ft].
BRAZIL
Salt
Dept
h, m
0
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
9,000
Overburden formations
Presaltoil
Rio de Janeiro
Espirito SantoBasin
Campos Basin
Santos Basin
So Paulo
Curitiba
SOUTHAMERICA
km 5000
mi 5000
control and diversion had been achieved (left).Moreover, the
bottomhole pressure exceeded thefracturing pressure throughout most
of the treat-ment, which had not been possible to achieveduring
previous attempts using conventionaldiversion techniques.
After the treatment, the well cleaned up inless than three days;
previously, four to ve dayshad been necessary. Prior to the
treatment, thegas production rate had been 8 MMcf/d[230,000 m3/d]
with a wellhead pressure of2,060 psi [14.2 MPa]. The posttreatment
produc-tion rate was 23 MMcf/d [650,000 m3/d]anearly threefold
increasewith a wellhead pres-sure of 2,230 psi [15.4 MPa]. The
excellent post-stimulation performance of this well has
beenobserved in the majority of other wells in thisregion treated
with the ber-laden acid.
Elimination of mechanical diversion tech-niques reduced the well
completion and stimula-tion time up to six days, resulting in a
savings ofUS$ 480,000 to US$ 600,000. As a result, theMaxCO3 Acid
system is now a prominent elementof Saudi Aramcos stimulation
strategy.
-
Autumn 2013 17
>Matrix acidizing treatment. In a presalt well offshore
Brazil, engineers pumped 13 uid stagesconsisting of alternating
portions of 15% HCl, VDA diverter and MaxCO3 Acid uid at various
pump rates(blue curve). A mixture of 15% HCl and a mutual solvent
preceded and followed the treatment. As thetreatment progressed,
the rig pressure (red curve) and bottomhole pressure (green curve)
rose,indicating that the bers were effectively diverting treatment
uid to zones with lower permeability.
0 1,00000
1,000
2,000
3,000
4,000
5,000
6,000
7,000
8,000
4
8
12
16
20
24
28
32
36
40
2,000 3,000
Time, s4,000
4,000
4,500
5,500
6,500
7,500
5,000
6,000
7,000
8,000
5,000 6,000 7,000 8,000 9,000 10,000
Pum
p ra
te, b
bl/m
in
Rig
pres
sure
, psi
Botto
mho
le p
ress
ure,
psi
HCl plus mutual solvent15% HClVDA fluidMaxCO3 Acid fluid
Stimulating Oil Production in Offshore BrazilIn South America,
the presalt region comprisesa group of oil-bearing carbonate
formationslocated in an offshore region along the coast ofBrazil
(previous page, bottom).16 The produc-ing formations occur at
depths between about4,500 and 6,500 m [14,800 and 21,300 ft] andlie
directly underneath a 2,000-m [6,500-ft]layer of evaporite
minerals. The reservoir tem-peratures vary between about 60C and
133C[140F and 272F].
The producing carbonate reservoir is a resultof the deposition
of mollusks followed by diagen-esis. Such reservoirs, called
coquinas, featurelarge variations in reservoir properties.
Porosityvaries from 5% to 18%, and permeability variesfrom less
than 0.001 mD to tens of mDs. Such het-erogeneity presents an
especially difcult diver-sion challenge during stimulation
treatments.
Engineers at Petrobras decided to evaluatethe MaxCO3 Acid
ber-assisted diversion tech-nology in a new well in the Pirambu
eld. Usingthe acid placement and diversion simulator,Schlumberger
engineers designed a matrixacidizing treatment for an interval
between4,500 m and 4,570 m [14,800 and 15,000 ft]. Thesimulator
called for a 790-bbl [12.6-m3],13-stage bullheaded treatment
consisting ofalternating volumes of 15% HCl, VDA uid andMaxCO3 Acid
uid with a ber concentrationbetween 100 and 120 lbm/1,000 galUS [12
and14 kg/m3]. The treatment was preceded by abrine and HCl mixture
containing a monobutylether mutual solvent.17 After the
treatment,engineers pumped another volume of HCl withmutual solvent
followed by diesel to acceleratewell cleanup. The pump rate varied
from 5 bbl/min[0.8 m3/min] during the MaxCO3 Acid uidstages to 10
bbl/min [1.6 m3/min] during theinjection of HCl and to 20 bbl/min
[3.2 m3/min]during the VDA diverter stages (above).
After well cleanup, engineers at Petrobrasevaluated the results
by performing productionlogging. The logs showed that the well was
pro-ducing from all of the treated zones as pre-dicted by the
simulator. Since this treatment,
Petrobras has continued to specify the use ofMaxCO3 Acid
fluid.
Rening MaxCO3 Acid TechnologyAs of this writing, more than 300
MaxCO3 Acidstimulation treatments have been performedaround the
world. In addition to the examplesfeatured in this article,
treatments have beenperformed in Kazakhstan, Angola, Canada, theUS,
Kuwait and the Caspian Sea.
As the number of treatments has increased,the larger treatment
database has allowed con-tinuous renement of the simulator and
improve-ment of stimulation results in naturally fracturedcarbonate
reservoirs. The technique has alsoallowed operators to reduce or
eliminate the useof ball sealers or packers, thereby reducing
costsand operational risks.
At present, work is underway to combineMaxCO3 Acid technology
with the ACTive family oflive downhole coiled tubing services. This
arrange-ment employs distributed temperature sensorsthat will allow
engineers to monitor uid place-ment in real time and change
treatment designsduring a job. Such exibility will further
enhancethe effectiveness of acidizing treatments employ-ing
ber-based uid diversion. EBN
16. Beasley CJ, Fiduk JC, Bize E, Boyd A, Frydman M,Zerilli A,
Dribus JR, Moreira JLP and Pinto ACC:Brazils Presalt Play, Oileld
Review 22, no. 3(Autumn 2010): 2837.
17. Mutual solvents are chemicals in which both aqueousand
nonaqueous compounds are miscible. Thesesolvents may be used to
prevent emulsions, reducesurface tension and leave formation
surfaceswater-wet.
