Reservoir Formation Damage Episode 3 Part 1 pps

Keelan and Koepf 1977 explain that "This test indicatesimpairment of productivity by clay hydration and movement of fines intothe formation during the drilling operation, and any benefit

where p c denotes the capillary pressure necessary for water retention, a

is the surface tension between water and hydrocarbon, 0 is the contactangle between the water and hydrocarbon, and r is the pore radius

Eq 15-1 indicates that water retention can be reduced by workoverschemes reducing the surface tension and/or increasing the contact angle

to favor a less water-wet condition

The Mud Damage Problem

Keelan and Koepf (1977) explain that drilling muds contain solidparticles that form a filter cake over the wellbore wall, the filter cakerestricts the mud flow into the near well bore formation, but some filtrateand fine particle invasion are unavoidable and usually occurs The filtratemay react with the resident formation clays causing clay swelling, mobili-zation, and migration The released particles and the fine particles carriedinto the formation by the filtrate can plug the pores and reduce permeability

of the formation The water-based filtrates increase the irreducible watersaturation and create water block and hydrocarbon permeability reduction

Evaluation of Drilling Muds—

Damage Potential and Removal

As depicted in Figure 15-11 by Amaefule et al (1988), the face of acore sample is exposed to mud under a pressure difference across the core

As described by Keelan and Koepf (1977), test sequences can be ducted with and without the presence of mobile hydrocarbons incore plugs Figure 15-12 by Keelan and Koepf (1977) delineates the testsequence without the presence of mobile hydrocarbons and shows theequations used to determine the magnitude of formation damage orremediation Keelan and Koepf (1977) explain that "This test indicatesimpairment of productivity by clay hydration and movement of fines intothe formation during the drilling operation, and any benefit of the fines'removal when the well flow in a reverse direction into the wellbore." Thecore plug is saturated with the brine to be tested and may or may notcontain irreducible, immobile oil Hence, the water-block effect is elimi-nated because the water saturation is constant During these tests, thefiltrate volume or rate versus the filtration time is measured until mud-off If the experimental design permits, the filter cake properties, such

con-as porosity, permeability, and thickness, and the effluent fines and liquidvolumes should also be measured The pressure difference applied to thecore plug should be determined by scaling from the planned drilling overbalance pressure (Keelan and Koepf, 1977)

Laboratory Evaluation of Formation Damage 483

Mud CirculationFlow Out: ^ _ Flow In:

Rinjection Pi,injection

Particulate Invaded Zone

Filtrate Invaded Zone

Fluid Flow:

toP

res

Figure 15-11 Core holder design for drilling mud evaluation systems (after

Amaefule et al., ©1988; reprinted by permission of the Canadian Institute ofMining, Metallurgy and Petroleum)

Figure 15-13 by Keelan and Koepf (1977) delineates the test sequencewith the presence of mobile hydrocarbons and shows the equations used

to determine the magnitude of formation damage or remediation Theyexplain that this test indicates "the water-block potential of a formation."

In this test, the water saturation varies and is calculated by measuringthe effluent filtrate volume Any permeability reduction remaining, afterthe production of all the injected, extraneous filtrate water, is attributed

to clay hydration and/or mud-solids invasion (Keelan and Koepf, 1977).Figure 15-14 by Keelan and Koepf (1977) depicts the results ofthe evaluation tests of two muds, referred to as Muds A and B Figure15-14 indicates that Mud A causes more damage than Mud B In the case

of Mud A, the return permeability is only 6% of the initial permeability,while it is 54% for Mud B

Keelan and Koepf (1977) conducted evaluation tests for two differentdrilling mud fluids, specially prepared for stabilizing the formation to

NO MOBILE HYDROCARBONS PRESENT

SAME AS MEDIUM K

% ACID IMPROVEMENT

NOTE PORE VOLUMES

OF FILTRATE REQUIRED, RATE OF FLUID LOSS, AND PRESSURE DROP

Figure 15-12 Test sequence without the presence of mobile hydrocarbons

(after Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society

of Petroleum Engineers)

avoid formation damage during water flooding Keelan and Koepf (1977)used fresh cores containing irreducible oil They recommend running testswith the presence of irreducible oil because they explain that "Thepresence of residual oil, or associated organic compounds, sometimesprotects clay surfaces, making them less sensitive to alteration whencontacted by incompatible brines." They injected coarsely filtered mud

Laboratory Evaluation of Formation Damage

MOBILE HYDROCARBONS

PRESENT 485

% ACID IMPROVEMENT

100

DAMAGE DUE TO MUD SOLIDS

<2) CLAY HYDRATION AND/OR MOVEMENT (T) RELATIVE

PERMEABILITY (WATER BLOCK)

Figure 15-13 Test sequence with the presence of mobile hydrocarbons (after

Keelan and Koepf, ©1977 SPE; reprinted by permission of the Society ofPetroleum Engineers)

filtrates (thus containing fine particles) into core plugs and measuredthe permeability impairment Figure 15-15 by Keelan and Koepf(1977) presents the results of injecting formation brine, filtrate, andinjection brine samples into the core plugs As can be seen, the effectivepermeability is 30% higher for KC1 mud filtrate compared to that oflignosulfonate mud filtrate

W»-1 r— — — ' 11

! ' AP'WO iP-500 IIUD "

?0 40 60 BO KX> 120 140 160 180 200

CUMMULAT'VE INJECTION '• PORE VOLUMES

Figure 15-14 Mud damage evaluation (after Keelan and Koepf, ©1977 SPE;

reprinted by permission of the Society of Petroleum Engineers)

„

^ Ul

1 2

* SAMPLES CONTAIN RESIDUAL 00.

Figure 15-15 Permeability to injection brine following exposure to KCI and

lignosulfonate mud filtrate (after Keelan and Koepf, ©1977 SPE; reprinted bypermission of the Society of Petroleum Engineers)

Laboratory Evaluation of Formation Damage 487

For purposes of remediation treatment after damage, Keelan and Koepf(1977) evaluated two types of acids: (1) "a regular mud acid contain-ing about 7 -i % inhibited HCI and a low surface-tension agent," and (2) amud acid "composed of 3% HF and 12% HCI." They explain that

"Recommended use of the HF acid required a preflush with 15% HCI,injection of the HF acid, and an after flush with diesel oil containing 20%

of a mutual solvent." Based on the results presented in Figure 15-16,Keelan and Koepf (1977) summarized their interpretation of the acidtreatment results as following:

1 Similar permeability reduction to each filtrate was noted in thesetest cores

2 In the cores contacted with KC1 filtrate, HF acid yielded 136%higher permeability to injection brine than did the regular mud acid,and resulted in a net permeability enhancement above initial Theregular mud acid was not effective, and final permeability to injec-tion brine was no higher than when the acid wash was not used

3 In the lignosulfonate-contacted cores, the regular mud acid and the

HF acid were equally effective, and each yielded a permeabilitygreater than the original

ft RECOVERY BY ACIDlZATION

CD MYDROflOWCiHF)

Figure 15-16 Permeability improvement by HF and HCI acid treatment following

exposure to KCI and lignosulfonate mud filtrate (after Keelan and Koepf, ©1977SPE; reprinted by permission of the Society of Petroleum Engineers)

4 In summary, either mud was suitable if HF acid was used forremedial treatment If the regular mud acid was to be used, the mostsuitable drilling mud would be lignosulfonate.

Evaluation of Hydraulic Fracturing Fluids

As explained by Keelan and Koepf (1977) fracturing fluids causeformation damage by water-block, solids invasion associated with fluidleak-off, and clay hydration in the near-fracture formation Therefore, it

is important to use compatible fluids and fluid-loss additives Hence, theyrecommend performing tests on core samples extracted from the reservoirformation, in which fractures will be created In these tests, the spurt loss,fluid-loss coefficient, effect of additives, acid solubility of formation, finesrelease with the acid reaction, are typically determined (Keelan andKoepf, 1977)

Evaluation of Workover and Injection Fluids

These tests indicate the incompatibility of clays with the extraneouslyintroduced water, including filtered formation brine and filtered mudfiltrate (Keelan and Koepf, 1977) Such tests can also be used to evaluatethe effectiveness of clay stabilizers added to workover and injection fluids(Keelan and Koepf, 1977) Keelan and Koepf (1977) state that "Use offiltered workover fluids removes plugging solids and results in evaluation

of damage resulting from clay swelling and/or clay-particle movement."The rock-water system is considered compatible when the formationpermeability does not decrease by fluid injection Keelan and Koepf(1977) state that

The clays damage productivity either by swelling in place or byrelease from their anchor point and subsequent movement to blockpore channels The inclusion of certain ions in workover and injectionfluids often offers a relatively inexpensive and effective stabilization

of the clays and prevention of productivity impairment

Figure 15-17 by Keelan and Koepf (1977) presents the test sequenceand the equations necessary for determining formation damage for evalu-ation of the compatibility of the injection and workover fluids withthe formation clays Figure 15-18 by Keelan and Koepf (1977) showsthe results of injecting brines with and without KC1 and CaCl2 added.Injecting a brine, rather than the formation brine, into a core sample Areduced the permeability to 50% of its formation brine permeability.Injecting a brine containing 100 ppm KC1 into a core sample B doubled

ED g

i

5 1

» r^

0

1

§

MIXED WITH INJECTION BRINE

Figure 15-18 Permeability to injection brine with and without KCI and CaCI2addition (after Keelan and Koepf, ©1977 SPE; reprinted by permission of theSociety of Petroleum Engineers)

its formation brine permeability However, injecting a brine containing

100 ppm CaCl2 reduced the permeability to 50% of its formation brinepermeability Figure 15-19 by Keelan and Koepf (1977) shows thatconsecutively decreasing concentrations of KCI and CaCl2 in the injectedbrines yields permeabilities above the initial formation brine permeability.Keelan and Koepf (1977) concluded that KCI treatment is favorable eventhough the data appear unusual

Keelan and Koepf (1977) recommend the water-oil relative ability measurements as a practical approach to damage assessment incore plugs Keelan and Koepf (1977) express that the fluids compatiblewith the core material should typically yield the relative permeability

perme-curves similar to those shown between the AA' and BB' lines in Figure

15-10 However, Keelan and Koepf (1977) explain that, when a filteredinjection brine is injected into a core containing irreducible oil, a specificvalue of the water relative permeability, denoted by Point E in Figure15-10, is obtained This particular value represents the water relativepermeability at the injection-wellbore formation face Whereas, the waterrelative permeability at a sufficiently long distance from the well bore isrepresented by Point B

Laboratory Evaluation of Formation Damage 491s.v

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-II:

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5 DD

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Q

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9K

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-* MIXED WITH INJECTION BRINE

Figure 15-19 Permeability with reduced concentrations of KCI and CaCI2solutions (after Keelan and Koepf, ©1977 SPE; reprinted by permission ofthe Society of Petroleum Engineers)

Evaluation of Workover Damage and Remedial Chemicals

Figure 15-20 by Keelan and Koepf (1977) describes the testing schemesand equations necessary for determining the damage and evaluation ofremedial chemical treatment of water block Keelan and Koepf (1977)facilitate surface tension reducing chemicals to remove the water formingthe water-block

Critical Interstitial Fluid Velocity and pH for

Hydrodynamic Detachment of Fines in Porous Media

The drag force acting upon a fine particle attached to the pore surface

is proportional to the interstitial velocity and viscosity of the fluid andthe surface area of the particle, as discussed in Chapter 8 As the fluidvelocity is increased gradually, a critical velocity necessary for detach-ment of fine particles from the pore surface can be reached Amaefule et

al (1987) state that "The critical velocity is dependent on the ionicstrength and pH of the carrier fluid, interfacial tension, pore geometry

-MOBILE HYDROCARBONS

PRESENT-K GAS @ IRREDUCIBLE Sw

INJECT WORKOVER FLUID

K GAS AFTER WORKOVER

VS GAS VOLUMES

INJECT REMEDIAL CHEMICALS

K GAS AFTER TREATMENT

VS GAS VOLUMES

SAME TESTS AS MEDIUM K

% DAMAGE RATIO AFTER WORKOVER=

" x l O O

K B

DAMAGE DUE TO

1 CLAY HYDRATION AND/OR MOVEMENT

2 SOLIDS IN WORKOVERAND REMEDIAL SOLUTION

3 RELATIVE PERMEABILITY (WATER BLOCK)

Figure 15-20 Test sequence for evaluation of workover fluid damage and

remedial chemicals (after Keelan and Koepf, ©1977 SPE; reprinted bypermission of the Society of Petroleum Engineers)

Laboratory Evaluation of Formation Damage 493

and morphology, and the wettability of the rock and fine particles." Then,

the particles are hydrodynamically removed from the pore surface andentrained by the fluid flowing through porous media Fine particlesmigrating downstream with the fluid may encounter and plug narrow porethroats by a jamming process This causes the pressure difference acrossthe core to increase and the permeability to decrease Therefore, from apractical point of view, the critical interstitial velocity is characterized

as the interstitial velocity at which permeability reduction and pressuredifferential increase begin as the fluid velocity is increased gradually from

a sufficiently low value (Gruesbeck and Collins, 1982; Gabriel andInamdar, 1983; Egbogah, 1984; Amaefule et al, 1987, 1988; Miranda andUnderdown, 1993)

The theory of the critical velocity determination is based on Forchheimer's(1914) equation, given below, which describes flow through porous mediafor conditions ranging from laminar to inertial flow:

AP U

Figure 15-21 Method for laboratory determination of critical velocity for

particle mobilization (after Amaefule et al., ©1988; reprinted by permission

of the Canadian Institute of Mining, Metallurgy and Petroleum)

Amaefule et al (1988) However, when the fluid velocity is graduallyincreased, first a critical velocity at which particle detachment by hydro-

dynamic forces begins, is reached, and then the value of Ap/v or Ap/q

continuously increases (Figure 15-2la) and permeability tinuously decreases (Figure 15-21b) by fines migration and deposition

con-in porous media As emphasized by Amaefule et al (1987, 1988), the

increase in A/?/v or Ap/q at high flow rates may be due to both fines

migration and inertial flow effects (Figure 15-21c) For decoupling thesetwo effects, Amaefule et al (1987) propose a subsequent velocity reducing