Reservoir Formation Damage Episode 2 Part 10 pot

Drilling damage in horizontal wells can be very high because of the long exposuretime during drilling mud damage and the mechanical action of thedrill pipe on the formation face; thus, t

Laboratory Evaluation of Formation Damage 457

bearing formations under actual scenarios of field operations, and forevaluation of techniques for restoration and stimulation of damagedformations are essential for efficient exploitation of petroleum reservoirs.Experimental systems and procedures should be designed to extractmeaningful and accurate experimental data The data should be suitablefor use with the available analytical interpretation methods This isimportant to develop reliable empirical correlations, verify mathematicalmodels, identify the governing mechanisms, and determine the relevantparameters These are then used to develop optimal strategies to mitigatethe adverse processes leading to formation damage during reservoirexploitation As expressed by Thomas et al (1998):

Laboratory testing is a critical component of the diagnostic cedure followed to characterize the damage To properly char-acterize the formation damage, a complete history of the well isnecessary Every phase, from drilling to production and injection,must be evaluated Sources of damage include drilling, cementing,perforating, completion and workover, gravel packing, production,stimulation, and injection operations A knowledge of each source

pro-is essential For example, oil-based drilling mud may cause emulsion

or wettability changes, and cementing may result in scale formation

in the immediate wellbore area from pH changes Drilling damage

in horizontal wells can be very high because of the long exposuretime during drilling (mud damage and the mechanical action of thedrill pipe on the formation face); thus, the well's history mayindicate several potential sources and types of damage

For meaningful formation damage characterization, laboratory coreflow tests should be conducted under certain conditions (Porter, 1989;Mungan, 1989):

1 Samples of actual fluids and formation rocks and all potential fluid interactions should be considered

rock-2 Laboratory tests should be designed in view of the conditions ofall field operations, including drilling, completion, stimulation, andpresent and future oil and gas recovery strategies and techniques

3 The ionic compositions of the brines used in laboratory tests should

be the same as the formation brines and injection brines involvingthe field operations

4 Cores from oil reservoir should be unextracted to preserve theirnative residual oil states

This is important because Mungan (1989) says that "Crude oils,especially heavy and asphaltenic crudes, provide a built-in stabilizing

458 Reservoir Formation Damage

effect for clays and fines in the reservoir, an effect that would be removed

by extraction."

Fundamental Processes of Formation Damage in Petroleum Reservoirs

Formation damage in petroleum-bearing formation occurs by variousmechanisms and/or processes, depending on the nature of the rock andfluids involved, and the in-situ conditions The commonly occurringprocesses involving rock-fluid and fluid-fluid interactions and their affects

on formation damage by various mechanisms have been reviewed bynumerous studies, including Mungan (1989), Gruesbeck and Collins(1982), Khilar and Fogler (1983), Sharma and Yortsos (1987), Civan(1992, 1994, 1996), Wojtanowicz et al (1987, 1988), Masikewich andBennion (1999), and Doane et al (1999)

The fundamental processes causing formation damage can be classified

as absorption, adsorption, wettability change, swelling, and (d) damage

by other processes, such as counter-current imbibition, grinding andmashing of solids, and surface glazing that might occur during drilling

of wells (Bennion and Thomas, 1994)

Laboratory Evaluation of Formation Damage 459

Selection of Reservoir Compatible Fluids

Figure 15-1 by Masikewich and Bennion (1999) outlines the typicalinformation, tests and processes necessary for laboratory testing andoptimal design, and selection of fluids for reservoir compatibility Hence,Masikewich and Bennion (1999) classify the effort necessary for fluidtesting and design into six steps:

1 Identification of the fluid and rock characteristics

2 Speculation of the potential formation damage mechanisms

3 Verification and quantification of the pertinent formation damagemechanisms by various tests

4 Investigation of the potential formation damage mitigation techniques

5 Development of the effective bridging systems to minimize and/oravoid fluids and fines invasion into porous media

6 Testing of candidate fluids for optimal selection

Experimental Set-up for Formation Damage Testing

The design of apparata for testing of reservoir core samples with fluidsvaries with specific objectives and applications Typical testing systemsinclude core holders, fluid reservoirs, pumps, flow meters, sample col-lectors, control systems for temperature, pressure or flow, and dataacquisition systems The degree of sophistication of the design of thecore testing apparatus depends on the requirements of particular testingconditions and expectations Figures 15-2, 15-3, and 15-4 by Doane et

al (1999) describe, respectively, the typical designs of a primitive systemthat operates at ambient laboratory temperature, and overbalanced andunderbalanced core testing apparata that operate at reservoir temperature.High quality and specific purpose laboratory core testing facilitiescan be designed, constructed, and operated for various research, develop-ment, and service activities Ready-made systems are also available inthe market

The schematic drawing given in Figure 15-2 indicates that primitivecore testing systems consist of a core holder, a pressure transducercontrolling the pressure difference across the core, an annulus pump toapply an overburden pressure over the rubber slieve containing the coreplug, a reservoir containing the testing fluid such as a drilling mud

or filtrate, a displacement pump to pump the testing fluid into the coreplug, and an effluent fluid collection container, such as a test tube.There is no temperature control on this system It operates at ambientlaboratory conditions

Laboratory Evaluation of Formation Damage 461

<D

Figure 15-2 Primitive drilling fluid evaluation system (after Doane et al.,

©1999; reprinted by permission of the Canadian Institute of Mining, Metallurgy and Petroleum).

The schematic drawing given in Figure 15-3 shows the elements of

a typical overbalanced core testing apparatus This system has beendesigned for core testing at near-in-situ temperature and stress conditions,although other features are similar to that of the primitive system shown

in Figure 15-2 The schematic given in Figure 15-4 shows the elements

of a typical underbalanced core testing apparatus, which also operates atnear-in situ temperature and stress conditions

Special Purpose Core Holders

Core flood tests can be conducted in one-dimensional linear (Figures15-2, 15-3, and 15-4) and radial modes Figures 15-5a-d by Saleh et

al (1997) show a schematic of typical radial flow models Radial models

(text continued on page 466)

High Pressure

N2 or Air Source

Vacuum

To Annulus Pump

Figure 15-3 Current reservoir condition fluid leak-off evaluation system (after Doane et al., ©1999; reprinted by permission

of the Canadian Institute of Mining, Metallurgy and Petroleum)

o

o O P P era

Figure 15^4 Underbalanced reservoir condition fluid leak-off evaluation system (after Doane et al., ©1999; reprinted by

permission of the Canadian Institute of Mining, Metallurgy and Petroleum) £

464 Reservoir Formation Damage

FIGURE is not to scale welded flanges with a rubber gasket

(a)

Berea core with a horizontal wellbore core holder can accommodate 3 " diameter, piston with' 4 feet long cores

double 0-rlng nof|2Oflta| we |, bore di am eter = 0.25" or 0.5"

rubber gasket required to seal off the

core faces

Pr*Mur*R*guUtor

(b)

Figure 15-5 Systems for horizontal wellbore studies: (a) core holder design,

(b) overall productivity evaluation, (c) overall injectivity evaluation, and

(d) drilling fluid evaluation (reprinted from Journal of Petroleum Science

and Engineering, Vol 17, Saleh, S T., Rustam, R., EI-Rabaa, W., and Islam,

M R., "Formation Damage Study with a Horizontal Wellbore Model, pp

87-99, ©1997; reprinted with permission from Elsevier Science)

Laboratory Evaluation of Formation Damage 465

I Brine Supply Reservoir

Sma« annular clearanct allows Hula

movement to production ports

Collected brine

(d)

Collected Filtrate In graduated cylinders

Figure 15-5 continued

466 Reservoir Formation Damage

(text continued from page 461)

better represent the effect of the converging or diverging flows in thenear-wellbore formation However, linear models are preferred for con-venience in testing and preparation of core samples

The majority of the core flow tests facilitate horizontal core plugsbecause the application of Darcy's law for horizontal flow does notinclude the gravity term and the analytical derivations used for inter-pretation of the experimental data is simplified This approach providesreasonable accuracy for single-phase fluids flowing through small diametercore plugs However, when multi-phase fluid systems with significantlydifferent properties and paniculate suspensions are flown through the coreplugs, an uneven distribution of fluids and/or suspended particles canoccur over the cross-sectional areas of cores This phenomenon compli-cates the solution of the equations necessary for interpretation of theexperimental data In particular, errors arise because, frequently, thetransport phenomena occurring in core plugs are described as being one-dimensional along the cores In order to alleviate this problem, it is moreconvenient to conduct core flow tests using vertical core plugs Conse-quently, the gravity term is included in Darcy's law, but errors associatedwith uneven distribution of fluid properties over the cross-sectional area

of the core plugs are avoided Therefore, Cernansky and Siroky (1985)used a vertical core holder

The dimensions of the core plugs are important parameters and should

be carefully selected to extract meaningful data Typically 1 to 2 in (2.54

to 5.08 cm) diameter and 1 to 4 in (2.54 to 10.58 cm) long cores areused The aspect ratio of a core plug is defined by the diameter-to-lengthratio Small diameter cores introduce more boundary effects near thecylindrical surface covered by the rubber slieve This, in turn, introduceserrors in model-assisted data interpretation and analysis when one-dimensional models are used, as frequently practiced in many applicationsfor computational convenience and simplification purposes On the otherhand, short cores do not allow for sufficient distance for investigation ofthe effect of the precipitation and dissolution processes and depth ofinvasion (Fambrough and Newhouse, 1993; Gadiyar and Civan, 1992;Doane et al., 1999) Longer cores are required for measurement of sec-tional or spatial porosity and permeability alteration

As described by Doane et al (1999), a number of special purpose coreholders have been designed Figure 15-6 shows a single core for whichonly the pressures at inlet and outlet ports can be measured This type

of system is usually used with small core plugs It only yields coreresponse, integrated over the core length As shown in Figure 15-7, longcores equipped with intermediate pressure taps can provide information

Laboratory Evaluation of Formation Damage 467

Mud Out

Direction

Figure 15-6 Core holder design for drilling fluid leak-off evaluation systems

(modified after Doane et al., ©1999; reprinted by permission of the CanadianInstitute of Mining, Metallurgy and Petroleum)

on sectional permeability alteration over the core length Especially, coreholders designed for tomographic analysis using sophisticated techniques,such as NMR, Cat-scan, etc., may provide additional internal data.However, it is not always possible to obtain sufficiently long core plugs

In this case, several core plugs of the same diameter can be placed into

a long core holder to construct a long core (20-40 cm long) and capillarycontact membranes are placed between the core plugs to maintain capil-lary continuity (Doane et al., 1999)

As emphasized by Doane et al (1999), small diameter core plugs arenot sufficient for testing of heterogeneous porous rocks Therefore, full

468 Reservoir Formation Damage

-OIL FLOW RATE

CORE

•^ ^-•v-L BRINE

PRESSURE DROP PROFILE

Figure 15-7 Scale damage evaluation system allowing for measurement of

sectional pressure drops (after Shaughnessy and Kline, ©1983 SPE; reprinted

by permission of the Society of Petroleum Engineers)

diameter core plugs have been used to alleviate this problem But, Doane

et al (1999) warn, full diameter core plugs would not be representativewhen significant anisotropy exists between the horizontal and verticalpermeability, such as in typical carbonate formations For the latter case,they recommend the core holder arrangement shown in Figure 15-8

In this system, the two opposing side surfaces of the core plugsare flattened by facing off and the fluid is flown over the side surface

by means of a specially designed sleeve This provides larger surfacesexposed to fluid to include the effect of the heterogeneous features ofthe core plugs

Obtaining and testing representative samples of fractured formationsare difficult (Doane et al., 1999) Actual core samples containing naturalfractures are preferred, but they are often difficult to obtain because coresamples are usually poorly consolidated and may not include naturalfractures (Doane et al., 1999) Then, a hydraulic fracturing apparatus can

be used to prepare artificially fractured core plugs, as shown in Figure15-9 by Doane et al (1999)

Laboratory Evaluation of Formation Damage 469

Reservoir Fluid Source

Jo Annulus Pump

OilV

•Gas

Figure 15-8 Cross-flow fluid leak-off evaluation system for heterogeneous

full diameter cores (after Doane et al., ©1999; reprinted by permission of theCanadian Institute of Mining, Metallurgy and Petroleum)

Confining Sleeve

Fractured Core Sample

Collection Head

Figure 15-9 Core holder design for fractured core flow evaluation systems

(after Doane et al., ©1999; reprinted by permission of the Canadian Institute

of Mining, Metallurgy and Petroleum)

470 Reservoir Formation Damage

Guidelines and Program for Laboratory Formation Damage Testing

Recommended Practice for Laboratory

Formation Damage Tests*

Introduction

The following procedure has been designed to provide a methodologyfor assessing formation damage in a variety of testing situations Con-sequently, it is not rigorous in all areas and operator selection of theprecise method or technique used is necessary at several points in theprocedure This procedure will however serve to minimize variability intest results if it is accurately followed and, if departures from thisprocedure are documented, it will help in the comparison of data derivedfrom different tests

This procedure is not meant to provide detailed instructions on the use

of the various pieces of equipment referred to It is assumed that thereader will have a good working knowledge of the principles and practicesinvolved in formation damage testing

When reporting results obtained using this procedure, details of alldepartures from these recommendations should be recorded in the final reportalong with details of methods used where more than one option is provided

Core Preparation and Characterization

Cutting and Trimming the Plugs Plugs should be cut to give a

mini-mum diameter of 1 inch (2.54 cm) Larger plugs, sized to fit lar core holders are preferable The samples should have a minimumlength of 1 inch (2.54 cm) and should be taken from the center of thecore to minimize the impact of any coring fluid invasion The pluggingmethod and drill bit lubricant used during plugging will be determined

particu-by the state of preservation of the sample and the reservoir type

Cutting Consolidated Core A standard core analysis rotary core

plugger should be used with lubricant selected as below:

a Well preserved core If the core is well preserved then the priate fluid for the zone from which it is derived should be used;i.e formation brine or crude oil for an oil well and formation brine

appro-* Reproduced with permission of the Society of Petroleum Engineers from SPE 38154paper by Marshall et al., 1997 SPE