Reservoir Formation Damage Episode 3 Part 9 ppt

Alteration of fluid properties by various processes, including ity alteration by emulsion block and effective mobility changeThe impact of formation damage can be observed in a variety o

682 Reservoir Formation Damage

Reservoir Type Classification Review of Processes

Framework Char.

Pore System

Completion Methods

Surface Facilities

Operation

Well Testing

Previous Treatment History

Diagenetic Minerals Practices

Figure 22-1 Issues involving candidate selection and reservoir formation

damage studies (after Yeager et al., ©1997 SPE; reprinted by permission ofthe Society of Petroleum Engineers)

Task 2 Determination of Damage

RSCT Testing U.S Patent No.

Rock Mechanics Geochemical Simulation

Figure 22-2 Issues involving reservoir formation damage determination (after

Yeager et al., ©1997 SPE; reprinted by permission of the Society of leum Engineers)

Petro-perforations Figure 22-3 by Yeager et al (1997) shows a schematic of

a typical high-resolution video camera and a still image, indicating nificant wellbore scaling, obtained using this camera The video observa-tions also provide valuable information necessary for determination of theflow distribution that can be used to improve the accuracy of the well-test interpretation and identification of the formation damage mechanisms(Yeager et al., 1997) Pressure transient tests yield information on the

sig-permeability and formation thickness product, (Kh), and skin factor, s.

As pointed out by Yeager et al (1997), pressure transient tests onlyprovide information at a specific time, when the tests are conducted.Therefore, formation damage can be more effectively evaluated byconducting a series of tests over a length of time and also the true skinshould be determined after corrections for other effects, such as non-Darcy

or inertial effects (Yeager et al., 1997)

In openhole completed wells, core samples can be taken from the wellsusing a rotary sidewall coring tool (Yeager et al., 1997) The material onthe face of the extracted cores should be carefully preserved during thetransportation of the core for later analytical studies (Yeager et al., 1997)

Flbar Optic Cabla Planing Neck Cabta H«»d

Bow Spring*

Canwra lUrrtl Assembly

Camera Lam

Light Dome Pmaaun Housing

Bull Nose Plug

Figure 22-3 Typical downhole video image and elements of a downhole video

camera (after Yeager et al., ©1997 SPE; reprinted by permission of theSociety of Petroleum Engineers)

684 Reservoir Formation Damage

Pseudo-Damage Versus Formation Damage

Amaefule et al (1988) plainly stated that "Formation damage is anexpensive headache to the oil and gas industry." A number of factorscause formation damage in a complicated manner Amaefule et al (1988)grouped these factors in two categories:

1 Alteration of formation properties by various processes, includingpermeability reduction, wettability alteration, lithology change,release of mineral particles, precipitation of reaction-by products,and organic and inorganic scales formation

2 Alteration of fluid properties by various processes, including ity alteration by emulsion block and effective mobility changeThe impact of formation damage can be observed in a variety of ways,including (1) abnormal decline in well productivity or injectivity, (2) mis-diagnosis of potential pay zones as nonproductive, and (3) delay of pay-out on investment (Amaefule et al., 1988)

viscos-Hayatdavoudi (1999) points out that the analysis of production data iscomplicated because of:

1 Mechanical problems related to the tubing, safety valves, liftequipment, and wax, paraffin, and scale build-up in the tubing

2 Formation damage due to fines migration, development of skin,completion damage, and many other factors

3 Changes in reservoir conditions, like appearance of water-cut,changes in productivity index, and other related factors

Among other factors, the productivity or injectivity of wells depend

on the pressure losses that occur along the flow path of produced orinjected fluids As schematically depicted in Figure 22-4, pressure lossesmay occur at various locations along the well and in the reservoirformation Therefore, Piot and Lietard (1987) expressed the total skin of

a well as a sum of the pseudoskin of flow lines from the formationface to the pipeline and the true skin due to formation damage Here,the focus is on the near-wellbore formation damage problem Figure 22-5schematically depicts the damaged region around a well

Measures of Formation Damage

Formation damage can be quantified by various terms, including(1) damage ratio, (2) skin factor, (3) permeability reduction index, (4) flowefficiency, and (5) depth of damage

Non-damaged Reservoir Formation

Pseudo Damage (Total pressure

loss)

Actual Damage (Pressure loss by formation damage)

Figure 22-4 Pressure losses during production.

Skin Factor

The skin factor is a dimensionless parameter relating the apparent (oreffective) and actual wellbore radii according to the parameters of thedamaged region:

686 Reservoir Formation Damage

Figure 22-5 Schematic of a damaged zone in the near-wellbore (modified

after Ohen and Civan, 1989)

where s is the skin factor The skin factor is a lumped parameter

incor-porating the integral affect of the extend and extent of damage in the wellbore region Frequently, in reservoir analysis and well test interpre-tation, the skin factor concept is preferred for convenience and simplicity,and for practical reasons Therefore, many efforts have been made toexpress the skin factor based on the analytical solutions of simplifiedmodels relating well flow rate to formation and fluid conditions In thisrespect, incompressible one-dimensional flow in a homogeneous porousmedia formulation approach has been popular

near-Other cases, such as anisotropic elliptic and isotropic radial flowproblems can be readily transformed into one-dimensional flow problems,using respectively

the flow direction

The formation anisotropy ratio of permeability, |3, is defined followingMuskat (1937):

(22-3)

Although this transformation distorts the wellbore shape from the drical shape (Mukherjee and Economides, 1991), it can still be used forall practical purposes with sufficient accuracy

cylin-Permeability Variation Index (PVI)

The permeability variation index expresses the change of formationpermeability by near-wellbore damage as a fraction, given by

(22.4,

where K and K d denote the formation permeabilities before and afterdamage, respectively

Viscosity Variation Index (VVI)

The viscosity variation index expresses the change of fluid viscosity

by various processes, such as emulsification, defined by:

where (I and |irf denote the fluid viscosities before and after fluiddamage, respectively

688 Reservoir Formation Damage

The production loss by alteration of formation properties can beformulated as following

The theoretical undamaged and damaged flow rates for a state incompressible radial flow in a homogeneous and isotropicporous media are given, respectively, by (Muskat, 1949; Amaefule

reservoir drainage boundary fluid pressures, r w and r e are the wellbore

and reservoir drainage radii, and r d is the radius of the damaged region

The effective skin factor, s, is defined by (Craft and Hawkins, 1959):

Thus, substituting Eq 22-10 into Eq 22-9 yields the relationship betweenthe damage ratio and the skin factor as:

The economic impact of formation damage on reservoir productivity can

be estimated in terms of the annual revenue loss by formation damage per

well (FD$L) at a given price of oil, p, according to Amaefule et al (1988):

year day bbl DR

bbl unproduced | bbl theoretical } (22-12)

Figure 22-6 by Amaefule et al (1988) shows the typical curves of thedamage ratio and annual revenue loss per well as a function of thedamage radius and degree determined by Eqs 22-8 and 12, respectively.Because the degree of damage varies in the near-wellbore region, it ismore appropriate to express the total skin as a sum of the individual skinsover consecutive segments of the formation as (Li et al., 1988; Lee andKasap, 1998):

(22-13)

where N represents the number of segments considered (see Figure 22-7).

The production loss by alteration of fluid properties can be formulated

as following Rapid flow of oil and water in the near-wellbore regionpromote mixing and emulsification This causes a reduction in the hydro-

carbon effective mobility, k(K = K e /\Ji = Kk r /\Ji) (Leontaritis, 1998), because

emulsion viscosity is several fold greater than oil and water viscosities.High viscosity emulsion forms a stationary block which resists flow It

is called emulsion block If (U, and [i d represent the viscosities of oil andemulsion, respectively, and a steady-state and incompressible radial flow

is considered, the theoretical undamaged and damaged flow rates aregiven, respectively, by:

- Legend Radius of Damage (r<j) FT

X 0.26

O 0.50 -£ 1.0 4.0

Ratio of Damaged to Undamaged Zone Permeability (Kd/K e )

Figure 22-6 Effect of permeability impairment and damaged zone radius on damage ratio (after Amaefule et al., ©1988;

reprinted by permission of the Canadian Institute of Mining, Metallurgy and Petroleum)

90

CDC/3o

oap

Figure 22-7 Near-wellbore damaged zone realized as a series of sectional

damaged zones

Figure 22-8 by Amaefule et al (1988) shows the effect of emulsion block

on oil production rate according to Eq 22-16

The viscous skin effect can be expressed similar to Zhu et al (1999) as:

692 Reservoir Formation Damage

1000

WELL SPACING t 40 ACRES 1/&AINAGE RALIUSM-C60FEET WELLBORE RADlUS(r w ) =0.25 FEET

OIL V I S C O S I T Y , po = 0.3tp

THICKNESS, h = 50 FEET PERI/EABILITY,K e = 20nuJ DRAWDOWN PRESSURE , £P = 250psi

RADIUS OF EMULSION FILLED ZONE R<j FEET

Figure 22-8 Effect of near-wellbore emulsion block on oil production rate

decline (after Amaefule et al., ©1988; reprinted by permission of the CanadianInstitute of Mining, Metallurgy and Petroleum)

and incompressible fluid flow at a steady-state condition is given by(Mukherjee and Economides, 1991):

FE=

(22-19)

For practical purposes, flow efficiency of damaged wells has beencorrelated by means of the inflow performance relationship (IPR) For

example, Dias-Couto and Golan (1982) developed the following inflowperformance relationship for wells producing oil with average reservoirfluid pressures at or below the bubble point pressure:

where q d is the oil flowrate of the damaged well, q db is the oil flow

rate at the bubble point from a damaged well, q max is the maximum oil

flow rate at p wf = 0 from a non-damaged well, and q c is the maximumoil flow rate of the Vogel (1968) part of the generalized IPR Lekia andEvans (1990) express these by the following equations:

694 Reservoir Formation Damage

where d is the invasion depth in cm, p is the pressure in MPa, V f is thecumulative filtrate loss in cm3, (|> is porosity in percentage, and K is

permeability in jim2(~ Darcy).

Figure 18-5 given in Chapter 18 by Civan depicts the variation of thedepth of damage during mud invasion as a function of the pore volume

of filtrate invasion

Model-Assisted Estimation of Skin Factor

As demonstrated by Ohen and Civan (1991, 1992, 1993), skin factorvaries over time and can be predicted by means of a formation damagemodel Figure 22-9 depicts the approach used by Ohen and Civan (1992)for prediction of the skin factor associated with formation damageresulting from fines migration and clay swelling effects in the near-wellbore formation

Model-Assisted Analysis of the Near-Wellbore

Permeability Alteration using Pressure Transient Data

The modeling and parameter estimation methods for determination ofnear-wellbore permeability alteration from pressure transient analysis data

by Olarewaju (1990) are presented here

Olarewaju (1990) considered a reservoir system, composed of twoconcentric zones, denoted as zones 1 and 2 in Figure 22-10 Zone 1 islocated near the wellbore and its permeability has been altered by forma-tion damage or stimulation processes For example, zone 1 includes thenear-wellbore formation, in which permeability impairment occurs by mudfluid and particle invasion and the mud cake formed over the sand faceduring drilling Zone 2 represents the undamaged formation located

beyond zone 1 The permeabilities of zones 1 and 2 are denoted by K\ and K 2 and the radius of zone 1 of the skin effect region is r } The

external drainage radius of zone 2 is r 2 The objective is to estimate the

values of K { , K 2 , and TJ using build-up pressure test data, such as by

Olarewaju (1990) from a reservoir in which the permeability of a wellbore formation has been enhanced by acid stimulation Ultimately,this information will be used to determine the skin factor as a measure

near-of the effectiveness near-of the acid treatment

For this purpose, Olarewaju (1990) developed a simplified matical model by considering (1) a slightly compressible single phasefluid, (2) constant thick-horizontal reservoir, (3) a constant rate produc-ing well, and (4) a reservoir, as shown in Figure 22-10, with no-flowboundaries at the top, bottom, and external drainage radius

mathe-Petrographic data;

ToUl clay, o

Total authlgenlc fln«i

Fraction of smectltlo city mlnarals

Core Data:

langth and diameter

(Initial porosity and psrmeablllty

Test Fluid data

- K vs throughput

• Flnas produotlon va throughput

Obtain Model Parameters using the linear flow model and the automatic parameter estimation routine

SCALE TO NEAR WELLBORE CONDITIONS

Initialization:

-St Initial conditions around the wellbore

k, <P (J p,T,eto

t>0

Obtain fines concentration in suspension

and pressure distribution

Compute change In pore volume due to

Claysw.Kng

Flnas deposition

Obtain Radius of Damaged Zone

r » k / k O > 0.9905

Compute In-situ fines generation

determine fraction of non-plugging

pathway

Compute Instanteneous

-Porosity

-Permaabnty

Make design plots

Figure 22-9 Steps of integrated near-wellbore formation damage analysis

and prediction (after Ohen and Civan, ©1991 SPE; reprinted by permission

of the Society of Petroleum Engineers)

696 Reservoir Formation Damage

Figure 22-10 Composite of damaged and non-damaged regions realization

of a reservoir (after Olarewaju, ©1990 John Wiley & Sons Limited; duced with permission)

repro-The dimensionless partial differential equations of the Olarewaju (1990)model are given as following:

Zone 1 pressure equation'.

Zone 2 pressure equation:

subject to the following conditions of solution:

Initial conditions (uniform initial pressure):

Inner boundary condition (constant rate):

(22-27)

(22-28)

£>1

(22-29)

Outer boundary condition (no-flow):

698 Reservoir Formation Damage

In these equations, the indices 1 and 2 denote zones 1 and 2; r w , r e , and

r represent the wellbore and drainage radii and radial distance from the

center of the well, respectively; t is time, B is the formation volume factor, P t and P } denote the initial reservoir and zone 1 radius pressures,

|i is fluid viscosity, (|), K, and h represent the formation porosity, permeability, and thickness; c t is the total compressibility, and a =0.0002637 and (3 = 0.007082 are some constant factors resulting fromconversion from Darcy to field units

The skin factor is calculated by

Eqs 22-26 through 32 can be solved by an appropriate numerical method,such as by the finite difference method However, Olarewaju (1990)obtained an analytical solution for the wellbore fluid pressure in the terms

of the modified Bessel series / and K 0 , in the Laplace domain, as:

Pi = 4,000 psia, q = 8.27 STB/D, B = l.2l RB/STB, \i = 1 cp, and c t =

9.8 x 1CT 6 psr 1 Olarewaju (1990) began the history matching process by

the initial estimates of K { = 1 md, K 2 = 0.1 md, and r } = 5 ft and obtained

the best match with K { =9.82md, K 2 =0.05md, and r { =51 ft

Conse-quently, the skin factor was calculated as s = -5.29 using Eq 22-40.

However, Olarewaju (1990) warns that the solution is not unique because

an infinite number of combinations of K^, K 2 , and r, may yield the same

skin factor value

Continuous Real Time Series Analysis for Detection and Monitoring Formation Damage Effects

Akaike (1999) explains that "Time series analysis intends to grasp thecharacteristics of the temporal movement or the dynamics of an object,