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2 SPE 155079

predict. This leaves neighboring lower-quality zones unstimulated, preventing them from reaching their maximum potential. This may not be a problem in the initial production of the well or field, especially in gas wells that are not produced to their maximum potential, but there can be significant consequences to the long term production and recovery of the field. (Postl et al. 2009; Abou-Sayed et al. 2007, Shuchart et al. 2009). Successful matrix treatments therefore require the achievement of stimulation targets for each zone across the entire interval, with targets being based on the long term well and field productivity. The challenge of achieving full zonal coverage and optimal placement with matrix acidizing fluids still persists today (Thabet et al. 2009; Jairo et al. 2010; Cohen et al. 2010).

Various types of specialized simulation software are commonly used to design matrix acidizing and hydraulic fracturing treatments. Quality data input describing reservoir properties such as permeability, porosity, pressure, lithology, mineralogy etc. are required for reliable design preparation. Using a large number of precisely characterized and described zones enables stimulation software to predict stimulation treatments performance with greater accuracy. Using less than optimum zone data that is simplified or averaged due to the complexity and uncertainty of the reservoir tends to lead to an overestimation of the performance of many stimulation treatments. In practice, the complete and representative data necessary for optimum stimulation treatment design are rarely available. Even in the cases where a high quality data set is available, the key formation parameters considered in acid stimulation are still clouded by uncertainty. In many cases, during the execution of stimulations on wells with a poorly characterized reservoir, the treatment parameters (pump rate, wellhead pressure etc.) significantly differ from those predicted by the design software simulator, which often leads to a less than optimum treatment design and well stimulation.

Petrophysical Data for Stimulation Design Petrophysics in carbonates has always proven challenging due to difficulties in estimating basic petrophysical properties such as saturation and permeability from conventional log data (Ramamoorthy et al. 2010). Carbonates are made up of fossil fragments and other grains of widely varying morphology, and generally composed of comparatively unstable mineral species. The wide variability in morphology or carbonate grains can lead to highly complex pore shapes and size, and a range of dissolution, precipitation, and recrystallization processes can lead to additional complexity through ongoing modification of this pore geometry.

As mentioned, a comprehensive petrophysical evaluation such as lithology and mineralogy, pressure, porosity, petrophysical rock types, and permeability are required as main inputs for a stimulation design. Accurate petrophysical evaluation requires the integration of texture-sensitive logs such as nuclear magnetic resonance (NMR), borehole images, full waveform acoustic, and dielectric. Lithology and porosity evaluation in the presence of anhydrite or other minerals may require the use of neutron capture spectroscopy logs. Mineralogy evaluation of carbonates may not be difficult and can sometimes be accomplished with basic logs. This is true for several major carbonate formations. Distinction between calcite and dolomite can be done with a good photoelectric absorption (PEF) log available from most density logs today. In the absence of gas or very light hydrocarbons, calcite and dolomite can also be quantified using neutron and density logs. However, if the PEF log is affected by the presence of barite in the drilling mud or if anhydrite is present in the formation or if substantial light hydrocarbon effects are present, then accurate mineralogy is not possible from basic logs. Neutron capture spectroscopy provides a measure of sulfur, which can be used to estimate an accurate anhydrite volume. Neutron capture spectroscopy also provides a measure of magnesium, which can be used to discriminate dolomite from calcite in the absence of or in conjunction with the PEF.

The solution for lithology and porosity necessarily involves the integration of multiple measurements, each with unique sensitivity to different elements of the rock matrix and contained fluids. When light hydrocarbons are present, the porosity estimate may be biased if the measurements being used do not investigate the same volume of rock. Density, epithermal neutron porosity, and NMR read similar rock volumes and a hydrocarbon-corrected total porosity estimate are easily obtained. The thermal neutron porosity, however, read much deeper into the formation and is likely to be more affected by the presence of light hydrocarbon.

In most cases, permeability is the most important property that controls fluid flow in a porous media. Direct measurement of permeability, as a log, has not been accomplished. For carbonate reservoirs, where there is no simple relationship between porosity and permeability, the petrophysicist faces the difficult task of relating the measured log properties to core permeability. Historically, permeability has been estimated using porosity-permeability transforms generated through regression of core porosity and permeability data. These relationships, however, fail in predicting permeability in complex carbonates where digenetic processes introduce a higher degree of heterogeneity. The most obvious case where the relationship fails is with mouldic limestones, where significant non-connected porosity is present, giving permeabilities that are unproportionally low relative to porosity.

Knowledge of porosity and mineralogy alone is insufficient to determine the reservoir quality of carbonates. Carbonates are characterized by different porosity types with complex pore size distributions, which result in wide permeability variations for a given level of total porosity. A reservoir interval may appear to be reasonably homogeneous as uniform resistivity and porosity can lead to reasonably constant permeability over the main reservoir interval based on triple-combo logs. However, an NMR log may shows different pore size for the same value of porosity and such a change in pore size would result in a several

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4 SPE 155079

Various Stimulation Techniques and their Pitfalls due to Uncertainty Selecting an appropriate completion and stimulation technique depends on several important criteria. Often the production mechanism of the reservoir and the inflow to the wellbore over the lifetime of the project will dictate the selection. Generally, a stimulation technique is selected that can ensure all zones have maximum potential to flow following periods of differential depletion. Adequate stimulation of the higher quality zones can contribute greatly to overall productivity gains of the well. However, the lower quality zones in carbonates may still contain significant volumes of hydrocarbon and adequate stimulation may be crucial for the long term productivity of the well. Furthermore, pressure effects and differential depletion need to be accounted for in thick carbonates especially, as this too can be a controlling factor determining the preferred path of treatment fluids.

Diversion is critical step to ensure the success of matrix acid treatments. Unless effectively diverted, the treated region eventually becomes the sink for the acid, leaving other regions not adequately acidized. Two techniques can be applied to achieve acid diversion: mechanical diversion and chemical diversion. The fundamental difference between chemical and mechanical diversion is that a chemical diverting agent achieves diversion by increasing flow resistance insides the created channels and the matrix, whereas a mechanical diversion process controls the fluid entry point from the wellbore. Hence chemical diverting agents can be considered as an internal diverting agent, as opposed to the external mechanical diversion. Combination of these techniques is often practiced for added efficiency.

The conventional diversion techniques that have been used (individually or in combination) to matrix acidize thick carbonate reservoirs include the following:

1. Multiple and Independent Staging Approach 2. Multi-stage approach (with non-independent stages) 3. Coiled Tubing Conveyed treatments 4. Ball Sealers 5. Chemical Diverters 6. Limited-Entry Perforating 7. High-Rate Pumping

Each of these techniques has advantages and disadvantages; but also each has certain drawbacks in terms of uncertainty. Independent Multi-Stage Approach. This technique involves segregating the various zones or reservoir sections through physical means and stimulating them independently. This includes the use of Multi-stage permanent completions with sliding sleeves and packers to separate individual zone, straddle systems which can be shifted to stimulate zones one by one, or most simply, as is commonly done on exploration or appraisal wells, using a DST string to move from zone to zone, with each lower zone being plugged off.

This technique can be the most ideal, in that as long as the packers are sealing and the cement behind casing is sufficient, you can ensure that each of the major sections of the reservoir is receiving acid. Each of the sections can also be tested independently before and after each stimulation, thereby obtaining accurate reservoir properties as well as post-stimulation skin reduction for each zone. However, due to the obvious operational and financial limitations involved in making numerous small stages across thick carbonates, this technique is usually combined with others, such as chemical diverters. The chemical diverters will account for permeability contrast within individual stages, however, if contrast is too high (i.e. natural fractures or fissures are present), or overall permeability-height (kh) is too large relative to pump rate, stimulation coverage may still suffer. Multi-stage Approach (with non-independent stages). This involves perforating and stimulating only low perm zones first. After this initial stage, another stage is perforated (of higher perm formation) and a new stimulation is performed. The key difference between this technique and the technique with independent stages is that the 2nd stimulation is performed with the 1st and 2nd stage perforations open and able to receive treating fluid. This cycle can be repeated to create additional non-independent stages. As is well documented, this technique is advantageous in that it ensures the 1st stage interval (low perm) receives a controlled amount of acid (again, as long as there is good cement integrity behind casing) and foregoes the time and risk involved in the more rigorous approach of using bridge-plugs to isolate zones. However, strong petrophysical understanding is required to master this technique, because there is a strong dependence between the stages and uncertainty or inaccuracy in one stage will affect the results of the next stage. For instance, if the total kh in the first stage is too small, the well may not be able to cleanup properly. If the total kh in the 1st stage is too high, the overall stimulation of the 2nd stage interval may be sacrificed. Especially if the contrast in the 2nd stage is high, the lower perms sections of the 2nd stage may have trouble competing with the highly stimulated zones of the 1st stage, which also may be hydrostatically preferred. Stimulating Through Coiled Tubing (or Drillipipe). Coiled Tubing is currently an important means of performing acidizing. It provides a conduit through which acid can be precisely spotted downhole. This can be very important in horizontal wells as it is a means of ensuring acid can contact the entire wellbore. Without it, or drill pipe conveyance, there would be no way of ensuring acid could reach the toe of a horizontal without reacting along the wellbore or being injected into more permeable zones uphole. By jetting acid throughout the wellbore, mechanical damage from filter cake can be removed.

SPE 155079 5

Coiled tubing offers several advantages over the conventional bullheading treatments during a matrix acid stimulation. Performing acid treatment through coiled tubing avoids exposing the wellhead or completion tubular to direct contact with corrosive fluids. Spotting the treatment fluid with coiled tubing will ensure the delivery of the treatment fluid against the target section, and will minimize initial wellbore fluids from being injected into the formation. When combined with chemical diverters, coiled tubing provides much better chance for success in acid coverage. The drawback of coiled tubing is that the tubing diameter is much smaller than that of drill pipe or production tubing used for bullheading treatments. Therefore, the injection rate is limited in situations when sustained high rate and pressure are required. Another disadvantage of using Coiled Tubing is that although it can be used to control where the acid initiates flow across the interval, it can not control where it is injected into the formation. Generally for stimulating thick carbonates with high kh, unless independent stages are being using, powerful diversion and/or high pump rates are needed. These high rates are often not achievable through Coiled Tubing. Ball Sealers. Ball Sealers are a means of mechanical diversion that are meant to block acid from entering the perforations of an already stimulated zone. Although they provide a powerful and easy way to promote diversion, they have considerable downside risk, especially when considering uncertainty:

i) It is common for the balls not to seal properly ii) There can be risk of the ball sealers not flowing back, or damaging surface equipment when they do iii) The timing and sequence for dropping the balls depends your petrophysical knowledge. Balls can either be

dropped continuously throughout the treatment or in stages, but once a ball hits the perforations, if it seals, flow will be shut off to the zone with no assurance that that zone had received an adequate stimulation or not (or was over stimulated). Hence, obtaining a uniform stimulation is very unlikely.

Chemical Diverters. Chemical diversion can be achieved through placing a viscous fluid, foam, or gel to help minimize the penetration of treatment fluid in the created wormholes and their surrounding matrix, or a particulate carrying fluid, which creates a filter cake on the surface of wormholes. This filter cake results in temporary skin effect which alters the injection profile. Gelled and foamed acids are also being used as a means of improving acid placement by combining stimulation and diversion in a single step. These are beneficial in that they guarantee at least a minimum amount of stimulation before diversion can take place. A downside of purely chemical base systems, however, is that viscosity generations alone often are not sufficient to divert from powerful features such as natural fractures, fissure, or faults. Furthermore, later stages of chemical diverters tend to work deeper into the reservoir, in the matrix ahead of the already formed wormholes. Although there are benefits to having diversion deep in the matrix, to help manage heterogeneity beyond the near-wellbore, diversion near the wellbore has a stronger impact on overall treatment pressure and the distribution of fluids. As was shown in Figs. 1 and 2, relying completely on chemical diversion can have drastic consequences. Limited Entry. Limited Entry has been used to stimulate thick carbonates through the use of low-shot density perforating. With few holes connecting the wellbore with the formation, significant perforation friction and back pressure is created. This increased pressure in the wellbore can forces stimulation fluids into zones with lower permeability, much the same way that chemical diverters do with viscosity. By combining limited entry with chemical diverters, powerful diversion can be obtained.

A key drawback of limited entry, especially with high rate gas wells, is the low-shot density can act as give a significant completion skin to the producing well; requiring higher drawdowns then would normally be required. Especially in wells that have very thin, high perm streaks, converging turbulent non-darcy flow is created which can literally choke the well. Ideally, perforation shot density could be adapted to promote/divert stimulation flow based on permeability to create an even flow injection profiles during stimulation, but given the significant uncertainty involved, the risks would be great. High Rate Pumping. Treatment pump rate during matrix stimulation jobs is another way to help control where stimulation fluids are going. The concept is also intrinsic to the limited entry concept. At a constant rate of flow into the wellbore from surface, if the channels for flow into the formation are reduced, the backpressure in the wellbore will be increased. This wellbore pressure can promote injection into zones with less injectivity. This is particularly true in those zones where the lesser injectivity comes from a smaller delta pressure due to partial depletion and/or hydrostatic gradient differences in thick gas reservoirs. Conversely, instead of reducing the perforation shot density, the flow rate can be increased which will create the same effect.

The limitations for high rate pumping are both technical and operational. The rate of pumping is limited by completion size and surface pressure limits, as well as bottomhole pressure limitations, which can involve both packer limitations and the fracture gradient. If the fracture pressure is exceeded, which itself can be a highly uncertain parameter, the diversion will be reduced significantly with the creation a hydraulic fracture with significantly more leakoff. Furthermore, depending on the operational environment, having a large amount of hydraulic horsepower available for every job in case high injectivity is encountered may be impractical.

6 SPE 155079

Managing Uncertainty with Treatment Design Each of the preceding diversion techniques, or a combination of them, can be valid ways to deal with formation heterogeneity in attempting to get a targeted stimulation coverage. However, as discussed, each is also prone to various pitfalls due to uncertainty in petrophysical properties. One effective way to manage the significant uncertainty encountered when stimulating carbonates has been found to be through the use of fiber-laden chemical diverters. This diversion system combines degradable fiber and a polymer-free viscoelastic diverting acid. It is designed to temporary block or decrease fluid leakoff into highly injective zones in carbonate reservoirs by creating fiber bridges within natural fractures, wormholes, and the perforations themselves. Also, the VES base fluid increases its viscosity as the acid spends, compounding the effect of the fibers. The combination of the self-diverting acid and fiber enhances the diversion process by combining the aspects of both particulate and viscosity-based diversion. After the treatment, the base fluid system breaks either on contact with hydrocarbon from the reservoir or with pre-flushes or over-flushes containing a mutual solvent. The fibrous component, which degrades as a function of temperature and time, requires the presence of a small amount of water supplied by the base fluid to degrade completely. The soluble byproducts then flow back and can be handled at surface using conventional techniques, as the stimulated reservoir is produced.

The powerful diversion, production enhancement and operational efficiency of this diverter is well documented, but one less obvious but important feature is its ability to give robust performance with predictable results, despite the significant petrophysical uncertainty involved. This has been shown in stimulation treatments of thick carbonates throughout the middle-east.

One of the main reasons for its ability to overcome uncertainty is due to an inherent property of the fiber itself, which allows for an automatic diversion adjustment downhole. When a media with infinite permeability, such as a perforation tunnel or natural fracture, is filled and bridged with a material of finite permeability such as degradable fiber, this creates a temporary skin to injectivity in that zone. It can be mathematically shown that the magnitude of this skin is proportional to the permeability of the formation; therefore the strongest impact is made on the most permeable zones with negligible effect on the least permeable zones (Cohen et al. 2010, Table 1). This is a powerful concept, as it is a way, despite uncertainty from a lack of logging data or uncertainty in the data itself, of dampening the natural permeability contrast of the reservoir. It does not rely on petrophysical certainty to design a successful treatment. Revisiting the simulated well stimulation of a thick heterogeneous carbonate, in Fig. 3, we show the same well treated using the fiber-laden diverter technology. Despite the highly permeable thief zone created by a natural fracture, the technology was able to divert flow to less permeable zones and get a much more even flow distribution than with the chemical diverter alone. These simulation results comply well with actual pressure-matched treatment results, with even wells that had significant drilling losses due to fractures showing significant pressure increases due to diversion.

It is also important to consider to the difference between fiber-laden chemical diverters and ball sealers. Although both provide mechanical diversion through interaction with the perforations, the mechanism and effects are different in important ways. Firstly, fiber laden chemical diverters have a liquid base that is a chemical diverter, so they can give diversion not only in the perforations but also in the formation. Furthermore, fiber laden diverters do not depend on having properly sized perforation entry holes and are more reliable than ball sealer. The fibers flow into the perforation tunnel and wormholes and gradually build a fiber cake and a diversion plug. Although the plug is strong, it is still permeable, and does not completely shut-off flow like a sealing ball. This means that the most permeable zones will continue to get fluid injection through the treatment, making the downside risk very low. After all, these zones are the most important to the overall productivity of a well, and therefore their adequate stimulation is essential. Flow is gradually diverted into a more even profile as more diverter is pumped, and this creates a more consistant diversion that is much less sensitive to uncertainty. Finally, the fibers degrade with temperature in a simple and reliable way and are therefore operationally easier to manage than ball sealers, with no detrimental effects to production.

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SPE 155

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e post-stimulazones with i

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TS). This way,regardless of

SPE 155

ity streak

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Figs. 16 andon profile. Agures as well a

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onclusions order to impro

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ailable. Even certainties, thderestimate raracterized rethe design so

mmon problemDue to high

sed on the knoverage across

ber technologytrophysical daThis is well

untries; despiiable. It is theplications witcount for the h

eferences Postl, D., El

Predictions. P Abou-Sayed,

IPTC 11660 Shuchart, C.

Without the Qatar, 7-9 De

Chang, F.F. Carbonate R3-5 Decembe

hole flowing pre

ove stimulatioeater number his, the reservn software canhowever, the c

in the caseshe reservoir prreservoir heteservoir, the troftware simulm in the induslevel uncertaiowledge of pethe entire inte

y within a visata, such as pealigned with tite high variaerefore recommth extreme pehigh levels of

llison, T.K., CPaper IPTC 136, I.S., Shuchartpresented at theE., Jackson, S.Use of Mechanecember. and Abbad, M

Reservoirs. Papeer.

essure – highe

on design withof separate z

voir model ben simulate withcomplete and s where a hiroperties are oerogeneity. Inreatment paramlator, which istry. inty in the keyetrophysical dervals can be co-elastic sur

ermeability anthe experienceability in condmended that t

ermeability councertainty th

Chang, D., et a622 presented a, C.E., Choi, ete International .K., Mendez-Sanical Isolation.

. 2008. Optimizer IPTC 12368

er permeability

h a greater acczones need toecomes more hh greater accurepresentativ

igh quality daoften simplifin many casemeters (pumpindicates a les

y parameters data, but also nachieved acrofactant base f

nd porosity, ane that has beenditions, the rethis fiber-load

ontrast, but alshat are always

al. 2009. Optimat the Internatiot al. 2007. WellPetroleum Techantiago, J., et aPaper IPTC 13

zing Well Prodpresented at th

contrast

curacy, it is imo be input togheterogeneousuracy stimulatve data necessata set is avied into large es, during thp rate, wellheass than optim

considered inneeds to take

oss thick, evenfluid. The divend can be succn seen in the Mesults obtaine

ded VES diverso in combinas present in ca

mization of Caonal Petroleum l Stimulation Thnology Conferal. 2009. Effect3621 presented

ductivity by Cohe International

Fig.18 – Lo contrast

mportant to inpgether with ides, but also motion treatmentsary for optimailable, due tzone clusters

he execution ad pressure et

mum treatment

n acid stimulatinto account t

n naturally fracersion techniq

cessful in a varMiddle East wed with fibererter is not onlation with va

arbonate stimu

arbonate StimuTechnology Co

Technology for rence, Dubai, Utive Stimulation

d at the Internat

ontrolling Acid l Petroleum Tec

ong term pro

put detailed reentified naturore representas performance

mum stimulatioto logging tos with averageof stimulatio

tc.) significant design and

tion, the stimuthe uncertaintctured, carbonque does not oriety of poten

when stimulatied diverter hly used for thearious other teulation.

lation based oonference, DohaThick, Middle

U.A.E., 4-6 Decn of Very Thictional Petroleum

Dissolution Pachnology Conf

oduction – hig

eservoir zonesral fractures seative. Using ae. on treatment ool resolutioned properties ons on wells

ntly defer fromwell stimulati

ulation shouldty. Maximizinnate intervals overly rely ontial scenarios ing thick carbave been vere most challenechniques disc

n Long-Term a, Qatar, 7-9 DeEast Carbonate

cember. ck, Layered Carm Technology

attern During Mference, Kuala L

SPE 155

gher permeab

s properties. Tections. Prope

accurate reserv

design are rarn limitations

that may gres with a poom those predicion. This is v

d not only desng treatment flusing degrada

n the accuracy

bonates in variry consistent nging stimulatcussed earlier

Well Performaecember. e Reservoirs. Pa

rbonate ReservConference, Do

Matrix AcidizinLumpur, Malay

5079

bility

That erly voir

rely and atly orly cted very

sign fluid able y of

ious and tion r, to

ance

aper

voirs oha,

g of ysia,

SPE 155079 13

5. Whitson, C.H. and Kuntadi, A. 2005. Khuff Gas Condensate Development. Paper IPTC 10692 presented at the International Petroleum Technology Conference, Doha, Qatar, 21-23 November.

6. Ansari, A. and Mahmoud, Y. 2009. Multi-Layer Testing: Theory and Practice. Paper IPTC 13546 presented at the International Petroleum Technology Conference, Doha, Qatar, 7-9 December.

7. Khalaf, A.S. 1997. Prediction of Flow Units of the Khuff Formation. Paper SPE 37739 presented at the SPE Middle East Oil Show, Manama, Bahrain, 15-18 March.

8. Chang, F.F., Qiu, X., and Nasr-El-Din, H.A. 2007. Chemical Diversion Techniques used for Carbonate matrix Acidizing: An Overview and Case Histories. Paper SPE 106444 presented at the SPE International Symposium on Oilfield Chemistry, Houston, Texas, U.S.A., 28 February-2 March.

9. Thabet, S., Brady, M., Parsons, et al. 2009. Changing the Game in the Stimulation of Thick Carbonate Gas Reservoirs. Paper IPTC 13097 presented at the International Petroleum Technology Conference, Doha, Qatar, 7-9 December.

10. Jairo, A., Ataur, R., Walter, N., et al. 2010. Field Trials of a Novel Fiber-Laden Self-Diverting Acid System for Carbonates in Saudi Arabia. Paper SPE 132003 presented at the SPE Deep Gas Conference, Manama, Bahrain, 24-26 January.

11. Cohen, C.E., Tardy, P.M.J, Lesko,T., et al. 2010. Understanding Diversion with a Novel Fiber-Laden Acid System for Matrix Acidizing of Carbonate Formations. Paper SPE 134495 presented at the SPE Annual Technical Conference and Exhibition, Florence, Italy, 19-22 September.

12. Ramamoorthy, R., Boyd, A., Neville, T. J., et al. 2010. A New Workflow for Petrophysical and Textural Evaluation of Carbonate Reservoirs. Petrophysics 51 (1): 17-31.