stimulating naturally fractured carbonate...
TRANSCRIPT
4 Oilfield Review
Stimulating Naturally Fractured Carbonate Reservoirs
Naturally fractured carbonate reservoirs can be difficult to stimulate because
treatment fluids tend to enter the fractures and avoid less permeable regions.
Effective fluid diversion techniques are usually necessary to ensure that stimulation
fluids contact the largest possible reservoir surface area. Engineers and chemists
have developed an innovative acidizing fluid that employs degradable fibers to
temporarily block permeable fractures and force the fluid into less permeable zones.
Operators have applied the fiber-laden acid to naturally fractured oil and gas reser-
voirs in which achieving complete zonal coverage is difficult and, as a result, have
witnessed substantial production improvements.
Khalid S. AsiriMohammed A. AtwiSaudi AramcoUdhailiyah, Saudi Arabia
Oscar Jiménez BuenoPetróleos Mexicanos (PEMEX)Villahermosa, Mexico
Bruno LecerfAlejandro PeñaSugar Land, Texas, USA
Tim LeskoConway, Arkansas, USA
Fred MuellerCollege Station, Texas
Alexandre Z. I. PereiraPetrobrasRio de Janeiro, Brazil
Fernanda Tellez CisnerosVillahermosa, Mexico
Oilfield 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, Macaé, 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,” Oilfield Review 4, no. 4 (October 1992): 24–40.
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): 19-2–19-3.
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 fluid 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 fluid 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 fluids 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 [KAlSi3O8–NaAlSi3O8–CaAl2Si2O6] par-ticles bound together by carbonate or clay miner-als. Silicate minerals do not react with HCl; they respond instead to stimulation fluids that contain hydrofluoric acid [HF] or fluoboric acid [HBF4].1
Despite the fluid 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 products—mainly calcium and magnesium chlorides—and 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 fluid flow during pro-duction. For efficient 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 flows preferen-tially into the most-permeable pathways. Higher-permeability areas receive most of the fluid and become larger, causing the treatment fluids to bypass lower-permeability regions where stimu-lation is needed most. To address this problem, engineers and chemists have developed methods
to divert acidizing fluids 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 fluids may be achieved using drillpipe or coiled tubing–con-veyed tools equipped with mechanical packers that isolate and direct fluid into low-permeability zones. Alternatively, flow 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 fluid flow during production.
6 Oilfield Review
the stimulation fluid as it travels down the well.The ball sealers are drawn to and seat againstperforations accepting the most fluid. After thetreatment, the ball sealers fall away, are mechan-ically dislodged or dissolve (above).
Chemical diverting agents incorporated instimulation fluids may be divided into two catego-ries—particulates and viscosifiers. Particulatesinclude plugging agents such as benzoic acidflakes 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 flow.
Viscosifiers 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 fluids 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-ionic—a neutral molecule that carries a positiveand a negative charge at separate positions.5
While being pumped down a well, VDA fluid—ablend of HCl, VES and common acid-treatmentadditives—maintains 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 fluid viscosity to increase (below). Thehigher-viscosity fluid forms a temporary barrierthat forces fresh acid to flow 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 fluid is exposedto hydrocarbons, which alters the ionic environ-ment and causes the micelles to become spheri-cal. Entanglement ceases, the micelles roamfreely, and the fluid viscosity decreases dramati-cally, enabling efficient poststimulation cleanup.Unlike polymer-base fluids, 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, theindustry’s considerable portfolio of diversiontechnologies has been inefficient in this environ-ment. Even when using self-diverting fluids 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 fluid to achieve stimula-tion, leading to higher treatment costs and lessthan optimal results.
However, Schlumberger engineers and chem-ists discovered that significant diversion improve-ments could be achieved by adding degradablefibers to VDA fluid. As fiber-laden diversion fluidenters a fracture, the fibers congregate, entangleand form structures that limit fluid entry. Thenew product, MaxCO3 Acid degradable diversionacid system, has been used successfully and effi-ciently to stimulate notoriously difficult 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 fluid. 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) fluid behavior during an acidizing treatment. Initially, when the surfactant is dispersed in acid, each molecule movesindependently throughout the fluid (left). As the acid reacts with the carbonate minerals, the surfactant molecules assemble and create elongated micelles(center). The micelles entangle and hinder fluid flow, resulting in higher fluid viscosity. When hydrocarbon production begins after the treatment, theelongated micelles transform into spheres (right), resulting in a dramatic decrease in fluid viscosity and facilitating efficient cleanup.
Surfactantmolecules
Elongated micelles Spherical micelles
Spent acid Hydrocarbon
CaCO3 + 2HCl CaCl2 + CO2 + H2O
Autumn 2013 7
This article describes the development of theMaxCO3 Acid system in the laboratory and itsintroduction to the oil field. Case histories fromMexico, Saudi Arabia and Brazil demonstratehow application of this new acid system is achiev-ing significant well productivity improvements.
Studying Fiber-Laden Acids in the LaboratoryFor more than 20 years, chemists and engineershave explored ways in which fibers could be usedto improve well servicing operations. Working
with both mineral- and polymer-base fibers, theydiscovered techniques for controlling the behav-ior of fluids 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 flexibility anddurability of well cements, aiding proppant trans-port during hydraulic fracturing operations andpreventing proppant flowback into the well aftera fracturing treatment.
Studying applications for fibers in the contextof acidizing has been a more recent endeavor. In2007, scientists at Schlumberger began exploringthe ability of fibers to improve fluid diversion inboth openhole and cased hole scenarios (above).The principal difference between the two condi-tions is that, for openhole completions, fibersmust accumulate along the entire wellbore sur-face to provide diversion, but in a cased holesituation, fiber deposition may be confined toperforations.
The engineers discovered that simply addingfibers to a conventional HCl solution failed to cre-ate a stable fibrous suspension. Shortly afteraddition, the fibers congregated, formed clumpsand separated from the acid. Success wasachieved by adding fibers to VDA fluid. The resul-tant higher fluid viscosity allowed the creation ofa robust suspension of discrete fibers.
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): 7-1–7-23.
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,” Oilfield Review 15,no. 4 (Winter 2003/2004): 28–45.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), fibers forma filtercake that covers the entire wellbore wall. During cased hole acidizing (top and bottom right),fibers form filtercakes 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): 121–127.
5. Sullivan P, Nelson EB, Anderson V and Hughes T: “OilfieldApplications of Giant Micelles,” in Zana R and Kaler EW(eds): Giant Micelles—Properties and Applications.Boca Raton, Florida, USA: CRC Press (2007): 453–472.
6. A micelle is a colloidal assembly of surfactant molecules.In the aqueous environment of an acidizing fluid, 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 Oilfield Review
The engineers then began performing exper-iments with laboratory-scale equipment forsimulating fluid leakoff and fiber deposition(above). The principal simulator was a bridgingapparatus that accommodated a variety of ori-fices through which fiber-laden acid could passat various flow rates. Circular orifices, withdiameters between 1 and 2 mm [0.04 and0.08 in.], simulated wormholes. Rectangular ori-fices with widths between 2 and 6 mm [0.08 and0.24 in.] were analogous to fractures. Engineersobserved fiber plug formation and recorded thecorresponding system pressure as fiber-ladenacid passed through an orifice.
> Laboratory-scale equipment for testing leakoff behavior and filtercake deposition. Engineers used a conventional filtration cell to simulate an openholestimulation (top). Technicians first placed a carbonate core at the bottom of the cell and then poured in fiber-laden acid. After sealing the cell, they applieddifferential pressure across the core and used a balance to measure the amount of filtrate passing though the core. For the cased hole simulation (bottom),engineers used a bridging apparatus. The apparatus consisted mainly of a 300-mL tube fitted with a piston, a high-performance liquid chromatography(HPLC) pump and an orifice (left). The orifice 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 fiber-laden acid. Acid exiting the tube passed through the orifice, and the techniciansassessed the diversion capability of fibers by measuring the filtrate volume, the fiber filtercake volume and the pumping pressure at various flow 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 fibers formed a bridge and began to fillthe orifice. These results indicated that as earlyvolumes of fiber-laden acid reach the perfora-tions, the acid penetrates the reservoir as if nofibers are present. Then, as the fibers bridge,they accumulate inside the perforations andform a filtercake. Next, the fibers plug theperforation, decreasing injectivity and promot-ing fluid diversion into other perforations.The engineers also discovered that the fiber
concentration required to achieve bridgingincreased with the fluid injection rate (nextpage, top right).
In the laboratory, after pumping the fiber-laden acid through the orifice, engineers per-formed a freshwater flush. As the viscous acidleft the apparatus, the pumping pressure gradu-ally decreased and eventually stabilized. At theend of each test, a stable fiber plug remained inthe orifice. Knowing the pressure, flow rate,fluid viscosity and fiber plug length, engineerswere also able to use Darcy’s law to calculatethe fiber plug permeabilities. Depending on thefiber concentration and the fluid flow rate dur-
Autumn 2013 9
7. It may appear counterintuitive to imagine that fiber plugswith permeabilities higher than that of the formationcould provide significant diversion. However, significantdiversion is also provided by the flow restriction andpressure drop as fluid 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 19–22, 2010.
> Pressure-versus-time plot from a slot-flow experiment. During thisexperiment, the MaxCO3 Acid composition consisted of 15 wt% VDA fluid and6 kg/m3 (50 lbm/1,000 galUS) degradable fibers. In Period 0, MaxCO3 Acid fluidbegins flowing through the slot, and the fibers have not yet formed a bridge.In Period 1, the pressure rises as the fibers 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 fiber plug remains intact and stable inside the slot (photograph).
Pres
sure
, psi
40
50
60
30
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10
0 10 20 30
Time, s40 50 60 70 80
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Fluid inflow
ing fiber deposition, the measured permeabili-ties varied between 400 and 2,400 mD. Thesedata led engineers to conclude that fibers wouldprovide the most efficient 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 offiber-laden acids under openhole and cased holeconditions; the model may be used to optimizetreatment designs.8 They performed 340 fine-scale3D simulations that evaluated typical perforationschemes, fibrous filtercake permeabilities andformation permeabilities. The resulting modelallows scientists to track the movement of the flu-ids and fibers through the wellbore and into thereservoir and track the propagation of wormholesgenerated as the acid reacts with carbonate rock.
> Effect of degradable fiber concentration onbridging ability in a slot. During the slot-flowexperiments, engineers determined that the fiberconcentration required to achieve bridging andpromote fluid diversion increases with the fluidinjection 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
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150
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adab
le fi
ber c
once
ntra
tion,
lbm
/1,0
00 g
alUS
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Nonbridging region
> Apparent permeability resulting from plugging a perforated zone withfibers. The x-axis shows the original core permeability. The y-axis shows theapparent zone permeability after a fibrous filtercake 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
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1
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10 Oilfield Review
> Diversion predictions from the MaxCO3 Acid simulator. During fiber deposition experiments in the perforation simulator, the permeabilities of the resultingfiber plugs varied between about 400 and 2,400 mD (left). The simulator predicts how the fiber plugs decrease the apparent permeabilities of reservoirs andpromote diversion. Lower-permeability fiber plugs are more efficient diverters. Modeling studies also demonstrated that fibrous filtercakes provide fluiddiversion by equalizing the permeabilities of layers in the treated interval. For example, if the interval contains four layers with various permeabilities, thefluid flow rate into the more permeable layers decreases and the fluid flow rate into the less permeable layers increases. Eventually, the flow ratesconverge to a single flow 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 filtercake surface area is lower.
Appa
rent
rese
rvoi
r per
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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 fluid batch mixing. The degradable fibers (top left) are light and finely divided, presenting a mixing challenge. Traditional equipment forbatch mixing of acidizing fluids was inefficient. Engineers discovered that equipment for batch mixing cement slurries (bottom left) could disperse the fibersin VDA fluid. The VDA fluid flows into an 8,000-L [50-bbl] paddle mixer (top right). To avoid the formation of clumps, field personnel manually add fibers to thefluid. After the fibers have been added, the tank is filled with more VDA fluid, and agitation continues until the mixture reaches a uniform consistency(bottom right). During the job, engineers maintain the agitation to preserve fluid uniformity.
Autumn 2013 11
9. For more on formation damage testing in the laboratory:Hill DG, Liétard 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): 14-31–14-33.
> Behavior of degradable fibers. Engineers performed static bottle tests during which degradablefibers were immersed in partially spent HCl fluids. The data show that the rate of fiber dissolutiondecreases as the HCl becomes neutralized. Nevertheless, complete fiber dissolution occurs within afew days (top). Core testing demonstrated that the acidic fiber degradation products may furtherstimulate the formation (bottom). Using a standard core testing apparatus at 115°C [239°F], engineerspumped 2% KCl solution into a limestone core first in the injection direction and then in the reverse, orproduction, direction (K0 and K1). Technicians recorded the pressure across the core and, applyingDarcy’s law, determined that the initial core permeability was 5.1 mD. Next, they injected a partiallyspent 20% HCl fluid (pH = 6.5) containing degradable fibers (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 fibers 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 fiber 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 100°C, %
20
20 30 40 50 60 70 80 90 100100
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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
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8
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In addition, the model predicts fluid diversionbehavior (previous page, top).
After demonstrating the diversion capabili-ties of fiber-laden VDA fluids in the laboratory,the developers considered the effects of fibers onreservoir productivity following an acidizingtreatment. If fibers remained in the wormholesindefinitely, their presence would hinder the flowof fluids from the reservoir to the wellbore. Forthis reason, degradable fibers were viewed as anattractive option. After a treatment, the fibershydrolyze and degrade within a few days. Theabsence of fibers leaves unobstructed wormholesand maximizes formation productivity. Further-more, the degradable fibers 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 suffi-ciently encouraging to allow the engineers toadvance to the next development stage—yardtesting to demonstrate that the fiber-ladenMaxCO3 Acid fluid could be prepared and pumpedefficiently and safely.
Verifying Wellsite DeliverabilityBecause matrix acidizing treatments typicallyconsume small fluid volumes compared withother stimulation techniques, engineers usuallyemploy batch-mixing procedures. By contrast,fracture acidizing usually requires large fluid 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 fibers safely and efficiently in thefluid and prepare a uniform suspension. Becausethe degradable fibers are light and finely divided,engineers were challenged to devise ways toimmerse the fibers in the VDA fluid so that theywould form a homogeneous mixture.
Experimentation led to the discovery thatuniform MaxCO3 Acid mixtures can be efficientlybatch mixed with existing equipment (previouspage, bottom). The equipment consists of a ves-sel, into which engineers pour the base VDA fluid,and an 8,000-L [50-bbl] recirculating mixing tankequipped with rotating paddles. Field personneldispense the fibers manually. Until the treatmentcommences, continuous agitation prevents fiberand fluid separation.
The POD programmable optimum densityblender is standard Schlumberger equipment forcontinuously dispensing solid materials such asproppant into fracturing fluids, and it proved to
be an efficient system for preparing MaxCO3 Acidmixtures. However, the fluid exit points must besecure to ensure that personnel are shieldedagainst fluid leaks and sprays. Therefore, engi-neers designed a special splash protection kit
12 Oilfield Review
10. Bullheading is the pumping of fluids into a wellbore fromthe surface with no direct control over which intervalswill accept the fluids.
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 7–9, 2009.
that includes a berm below the blender and aplastic sidewall (above left). They also developeda special chute for metering the degradablefibers as they are dispersed into the mixing tub.The modified chute, mounted directly above themixing tub, has no restrictions or bends thatmight hinder smooth fiber delivery.
After verifying that MaxCO3 Acid fluids couldbe prepared reliably with existing field equip-ment, the project team traveled to Qatar forfield testing. A principal test objective was toevaluate the accuracy of the acid placement anddiversion simulator.
Field Testing in QatarThe North field 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 fluid. A POD blender is outfitted with aspecial fiber 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 fluid spills. A plastic sidewall around the mixingtubs (bottom) further shields the mixing process.
Fiber feeder
> Qatar North field. Discovered in the 1970s, this accumulation is the largestgas field in the world, with estimated reserves as high as 25.5 trillion m3
[900 Tcf]. The reservoir is called the South Pars field on the Iranian side ofthe maritime border (dashed black line). The producing formation ischaracterized by large interzonal permeability contrasts—up 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 thedifficulty of achieving uniform stimulation in one treatment.
IRAN
QATAR
BAHRAINNorthField
SouthPars
SAUDIARABIA
0 km
0 mi 50
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SAUDIARABIA
IRAN
> Jujo-Tecominoacán field. This region is among the most prolific oil and gas producing areas insouthern Mexico. The reservoirs are naturally fractured and difficult to stimulate uniformly.
Villahermosa
TabascoState
Jujo-Tecominoacán 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 workflow for designing and per-forming a MaxCO3 Acid treatment consisted ofseveral steps. To build a reservoir model, engi-neers first 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 depth—between 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 field tests, installation ofbridge plugs had been the preferred technique toachieve fluid 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 Acidfluid containing 75 lbm/1,000 galUS [9.0 kg/m3]of degradable fibers. To ensure uniform fiber sus-pension, engineers set up the treatment so that160-bbl [25-m3] spacers of VDA fluid precededand followed the MaxCO3 Acid stages. During thetreatment, the simulated and measured bottom-hole pressures were in good agreement, provid-ing confirmation that the diversion physics ofMaxCO3 Acid behavior were well described by thesimulator (right).
After the success of the first test well, engi-neers performed 10 more acidizing treatments inthe field with similar results.11 The fiber-ladenacid performed as predicted, and operationalefficiencies 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 benefits included a 72%reduction in the emission of greenhouse gasesbecause of reduced flaring. Following the successof the Qatari field tests, the operator deployedMaxCO3 Acid technology in other regions.
> Permeability profile. The permeability varies four orders of magnitude in atest well in the Qatar North field.
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 field test in the Qatar North field. Engineers pumped fourstages of 28% HCl and MaxCO3 Acid fluid. A VDA fluid spacer preceded and followed each MaxCO3Acid stage to preserve fiber suspension uniformity. The excellent agreement between the measured(blue curve) and simulated (black) bottomhole pressures (BHP) helped confirm the validity of theMaxCO3 Acid placement model.
6,500
7,500
6,000
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Measured BHPSimulated BHPPump rate
Fluid at perforationsMaxCO3 Acid fluidWater
GasHCIVDA acid
Optimizing Production in Southern MexicoThe Jujo-Tecominoacán field, operated byPetróleos Mexicanos (PEMEX), is located 60 km[40 mi] from Villahermosa, Tabasco, in southern
Mexico (previous page, bottom). The field has48 producing wells and 19 injection wells tomaintain reservoir pressure. The average depthof the producing intervals is 5,000 m [16,400 ft],
14 Oilfield Review
and the reservoir temperature varies between120°C and 160°C [250°F and 320°F]. Wells in thisfield 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 137°C [279°F] 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 preflush toclean the perforations, 60 m3 [15,600 galUS] ofHCl–formic acid blend, 10 m3 [2,600 galUS] ofMaxCO3 Acid fluid containing 90 lbm/1,000 galUS[11 kg/m3] fibers 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 fluid and accelerate wellcleanup, and hydrocarbon production commencedwithin three days. The initial oil production rate,3,000 bbl/d [480 m3/d], exceeded PEMEX’s 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 field with favorable results.
> Pumping schedule for a matrix acidizing treatment in the Jujo-Tecominoacán field. During the 11-stage treatment, engineers pumped anaromatic solvent to clean up perforations, an HCl–formic acid blend,MaxCO3 Acid fluid and an ammonium chloride brine spacer. The final stagecontained nitrogen [N2] to enhance well cleanup.
Fluid NameStage Name Stage FluidVolume, m3
Nitrogen PumpRate, m3/min
Spacer 3% NH4Cl brine
Spacer 3% NH4Cl brine
Diverter MaxCO3 Acid fluid
Diverter MaxCO3 Acid fluid
Acid HCI–formic acid blend
HCI–formic acid blend
HCI–formic 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-Tecominoacán field. 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 1–3, 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): 26–33.
14. Aviles I, Baihly J and Liu GH: “Multistage Stimulationin Liquid-Rich Unconventional Formations,”Oilfield Review 25, no. 2 (Summer 2013): 26–33.
15. Jauregui JL, Malik AR, Solares JR, Nunez Garcia W,Bukovac T, Sinosic B and Gürmen 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 25–28, 2011.
Autumn 2013 15
> South Ghawar field 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 difficult fluid 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 fluid 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 280°F [138°C] 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 65°deviation. Three pay zones existed along a 240-ft[73-m] interval in the central sector of the field.From reservoir parameters obtained from open-hole logs, engineers concluded that, to meetSaudi Aramco’s 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 fluid stages that alternatedportions of a 35-lbm/1,000 galUS [4.2-kg/m3]borate crosslinked guar fracturing fluid, 28% SXEsuperX emulsified acid to retard the rate of acidconsumption, 28% HCl and 15% MaxCO3 Acid for-mulation with degradable fiber concentrationsbetween 75 and 175 lbm/1,000 galUS [9 and21 kg/m3] (right). During the treatment, after thefirst MaxCO3 Acid stage contacted the formation,engineers recorded a 4,500-psi [31-MPa] bottom-hole pressure rise—the first time such a largeincrease had been recorded in this carbonatereservoir—indicating that excellent fluid leakoff > Pumping schedule for an acid fracturing treatment in Saudi Arabia. The total fluid 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 insignificant operational cost savings.
Treatment Schedule
Fluid NameStage Name Stage FluidVolume, galUS [m3]
AcidConcentration, %
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 Oilfield 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 fluid 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 fields 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
São 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 five 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 increase—with 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 fiber-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 Aramco’s stimulation strategy.
Autumn 2013 17
>Matrix acidizing treatment. In a presalt well offshore Brazil, engineers pumped 13 fluid stagesconsisting of alternating portions of 15% HCl, VDA diverter and MaxCO3 Acid fluid 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 fibers were effectively diverting treatment fluid 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 60°C and 133°C[140°F and 272°F].
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 difficult diver-sion challenge during stimulation treatments.
Engineers at Petrobras decided to evaluatethe MaxCO3 Acid fiber-assisted diversion tech-nology in a new well in the Pirambu field. 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 fluid andMaxCO3 Acid fluid with a fiber 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 fluidstages 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.
Refining 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 refinement 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 fluid place-ment in real time and change treatment designsduring a job. Such flexibility will further enhancethe effectiveness of acidizing treatments employ-ing fiber-based fluid diversion. —EBN
16. Beasley CJ, Fiduk JC, Bize E, Boyd A, Frydman M,Zerilli A, Dribus JR, Moreira JLP and Pinto ACC:“Brazil’s Presalt Play,” Oilfield Review 22, no. 3(Autumn 2010): 28–37.
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.