Clay Minerals (1986) 21, 735-751

F O R M A T I O N D A M A G E A N D R E M E D I A L S T I M U L A T I O N

T . R . H A R P E R A N D D . C . B U L L E R

BP Research Centre, Chertsey Road, Sunbury-on-Thames, Middlesex TW16 7LN

(Received 2 December 1985; revised 18 January 1986)

A B S T R A C T : It is argued that a wide range of engineering data and geological data is required to make confident prognoses or diagnoses of formation damage. Potential sources of data are reviewed, with comments on their limitations. It is proposed that microscopic failure can cause formation damage in macroscopically intact rock at stress concentrations around the wellbore. The significance of natural fractures is reviewed in relation to formation damage induced by diagenetic mineralization or invasion by lost circulation material. Removal of such plugging material by acid stimulation is assessed in relation to diverting agent requirements.

In general, the poorer the quality of a reservoir, the greater the susceptibility to formation damage. The decrease in quality may relate to a greater content and diversity of diagenetic minerals, or to lithological complexity and an associated anisotropy and heterogeneity. A complex diagenetic history may also reflect a relatively complex tectonic history, leading to the development of small-scale structures (another form of heterogeneity), or to mechanical characteristics which promote other forms of formation damage.

Any formation damage potential is only realized during drilling, completion and production operations. Consequently, studies of susceptibility to damage have limited value if conducted without consideration of the engineering activities during which a damage potential may or may not be realized.

The practical significance of damage is dependent on the ease with which this can be avoided or rectified: changes of drilling, completion or production practice can obviate many forms of damage, whilst stimulation treatments can be used as a remedial measure. None of these measures can be implemented in a rational and optimized manner without first identifying the processes which give rise to the damage. Therefore, the practical significance of formation damage is also a function of the difficulty or otherwise of determining the cause.

Formation damage results from engineering activities involving geological materials, and concerns solely the efficiency of fluid flow between reservoir and wellbore. Consequently, any attempt to predict well performance on the basis of the clastic and diagenetic mineral assemblage in a reservoir pre-supposes a knowledge of the response of that mineral assemblage to both chemical changes and to fluid-pressure distributions of the type imposed by a well. Despite early attempts to predict the characteristics of even single phase, laminar fluid flow in homogeneous, monomineralic sandstones on the basis of grain-size distribution (Hazen, 1911), these predictions remain only approximate (Taylor, 1948). The need to conduct fluid flow experiments to determine permeability remains

1986 The Mineralogical Society

736 T. R. Harper and D. C. Buller

universally accepted. This suggests that prediction of the multiphase flow characteristics of argillaceous sandstones, a far more complex situation, should only be made with extreme caution in the absence of test data. This is a common engineering situation. The engineering performanc e of only the simplest system can be characterized by visual inspection alone. Multiphase flow through porous media cannot be regarded as a simple system.

Consequently, it is of limited benefit to focus on one aspect of the problem in isolation, whether this be the petrology of the hydrocarbon host rock or the engineering characteristics of the well which is used to exploit the resource. Predictions based on such isolated aspects may, of course, be required to meet operational needs. As noted, such interpretation is complex and the results merit a commensurate degree of caution.

The subsequent discussion of formation damage diagnosis is presented from a broad perspective of integrated engineering and geological studies. In addition, an aspect of the more specialized topic of natural fracture stimulation is addressed, the significance of any natural fractures becoming increasingly important as reservoir quality is reduced, either by diagenetic mineralization or other means.

C A U S E S OF F O R M A T I O N D A M A G E

For purposes of this discussion, formation damage is defined as any process which gives rise to a positive skin factor. The term skin factor is that introduced by van Everdingen (1953) and refers to near-wellbore pressure losses over and above that which would arise during radial flow to a wellbore in an homogeneous, isotropic medium. This is not a rigorous definition. For example, gas or liquid blocking which would give rise to a positive skin factor might not be regarded as formation damage; nor would some forms of partial penetration. Partial penetration could arise because of formation damage, however, where wellbore enlargement leads to poor communication in perforated completions. Any definition of formation damage is likely to be controversial, but to pursue this debate here would be of limited practical significance. We prefer simply to consider those processes which are relevant to well performance, and which are associated with positive skin factors observed in well tests. This approach is adopted because of the frequent need to diagnose the cause of impaired well productivity, and therefore the need to be aware of all possible causes. Remedial or avoidance measures can only be devised on a rational basis by first identifying the cause, or potential cause, of damage. In essence, the discussion concerns factors affecting well productivity impairment rather than the more restricted topic of formation damage because this approach has greater practical application.

In the most general sense, well productivity impairment can result from five mechanisms: (i) fluid/rock incompatibility; (ii) fluid/fluid incompatibility; (iii) departure from laminar, radial flow in an homogeneous, isotropic medium; (iv) mechanical deformation around the borehole or perforation tunnels; (v) reduction of fluid pressure during production.

Near-wellbore permeability reduction caused by fluid/rock incompatibility

The influential role of clay minerals on fluid flow in geological materials is widely recognized. Numerous authors (e.g. Gruesbeck & Collins, 1982) have noted that clay particle migration and deposition may occur. The circumstances in which this occurs are a

Formation damage and remedial stimulation 737

function of a number of variables. They include the chemistry of the clay mineral(s) and the chemical and electrochemical nature of both the natural pore-fluid and of the fluid which is introduced by hydrocarbon extraction operations. Clay swelling may also be induced by changes of pore-fluid. Other authors have noted that migration of particulate material other than clays may occur. Muecke (1979) analysed unconsolidated sandstones and observed that most of the fines present in the pore space were not clay minerals.

It would be imprudent to assume that fluid/rock incompatibility occurs only because of swelling and particle migration/deposition. Fig. 1 shows the result of a laboratory flow test in which fluid/rock incompatibility is inferred. A conventional oil-based mud filtrate was introduced into a reservoir sandstone containing a suite of clay minerals including mixed-layer illite-smectite, illite, chlorite and corrensite. A substantial loss of permeability was recorded. Fig. 2 reveals that a reformulated mud filtrate was not damaging to a sample of the same material. No evidence could be found to ascribe the apparent damage observed in the first test to fines migration, or to other recognized processes.

Whilst electrochemical forces should certainly not be ignored, an additional factor, the seepage forces, will also influence particle migration. Seepage force is the mechanical force acting to displace a particle in the presence of a fluid gradient (which can be extremely high in the vicinity of a wellbore). The seepage force, expressed as a force per unit volume of the porous medium through which flow occurs, is given for single-phase flow by iTi, where i is

PERMEABILITY (mD) FLOW RATE (ml /min)

1 0

6 �84

5

4 -

3 -

2 -

1 -

I |

!

i �9 -w !

- I

' I I ' 1 0 0 0 2 0 0 0 3 0 0 0

VOLUME (roll 1 = REFERENCE OIL -!- -!- REFERENCE OIL ---~

$ O M F

S O M F = 8 1 M U L A T E D O I L - B A S E D M U D F ILTRATE

FIG. ]. Damage incurred in laboratory core test by flow of off-based mud filtrate.

F O R W A R D

R E V E R S E

738

P E R M E A B I L I T Y ( m D )

T. R. Harper and D. C. Buller

F L O W R A T E ( m l / m i n )

6.0

5.5

5.0

4.5

4.0

3.5

3.0

2.5

2.0

1.5

1.0

0.5

0.0

ml

i i i i i i I I i i i i i ! i i 5 0 0 1 0 0 0 1 S00 2 0 0 0

F L O O D V O L U M E (m l )

0.3

0.25

0.2

0.15

0.1

0.5

0 0

0.5

0.1

0.15

0.2

0.25

0.3

R E F E R E N C E O IL _L_I_ R E F E R E N C E O IL - - ~ =F-I SOMF

'#4

SOMF SIMULATED OIL-BASED MUD FILTRATE

FIG. 2. Flow of oil-based mud filtrate through laboratory core: mud reformulated to avoid damage.

FORWARD

REVERSE

the fluid gradient and 7y is the unit weight of the fluid. The seepage force therefore depends on the nature of the fluid flowing in the porous medium (oil, water, gas). A threshold value representing the onset of particle displacement has been observed by several researchers. For example, Clementz (1982) has recorded a non-linear result from a laboratory flow test conducted at a series of pressure gradients (reported in terms of flow rate), which was associated with the displacement of fines from the core. Apart from the effect of seepage forces, however, several other mechanisms are known to cause a departure from Darcy linear relationships.

Damage may also be incurred by the use of drilling and completion fluids which introduce particulate matter into the near-wellbore region of the reservoir. Also, stimulation fluids can react adversely and precipitation fronts may be detrimental if the design of a treatment is inadequate.

Near-wellbore permeability reduction caused by fluid/fluid incompatibility

Not infrequently, serious well productivity problems can be attributed to incompatibifity of fluids. Incompatibility may arise between introduced fluids and reservoir pore-fluid (e.g. emulsion blocks produced by mixing mud acid and some crude oils, scale) or between fluids

Formation damage and remedial stimulation 739

introduced into the well (e.g. between various additives in a chemical stimulation package). Incompatibility of introduced fluids can be avoided by careful treatment design and quality control. Incompatibility of reservoir fluid and introduced fluid may be controlled by use of preflush/afterflush techniques and limitation of residence time in the reservoir (but may be rendered only partially effective by irregular distribution of fluids or reactive rock in the near-wellbore region).

Introduced solids may also occasionally be chemically incompatible with reservoir fluids. Fig. 3 illustrates an example of this. In this laboratory test, a granular solid used to control lost circulation in a series of development wells in the Middle East was mixed with a simulated formation water from the reservoir in question. Although the degree of mixing in laboratory and field will be different, the resulting colloidal sludge formed at reservoir temperature clearly demonstrates an incompatibility between the drilling material and reservoir fluid.

~i~i!~ !i ~ii~ '~ i~i!ii~i~iii~i~ ~ii!i!iil ~II i~!i ~I! ~ i~ iii~i~!ii~'~i~ii!!~!/~ ~ ~ / / ~ ~i!~' !~i~/~i~i~i!~ilil ~ ~i~ ~i ~i/~i~i~ ili~ili~!!i!!il i liii~iiii!i ~

iiiiiii!ii!iiiiiiiiii+ill i~ ~ i ii!! i iiiiiii! , i l i i i

~ii~i~i/~ ~ ~ii~ �84 iil II~�84 !!!ii ~ ~i~/ii~i~iii~i !�84 ii, ,, ~!!

FIG. 3. Compatibility of lost circulation material and formation water (a) at 52~ to simulate cooling during mud circulation: (b) at 93 ~ C (reservoir temperature).

740 T. R. Harper and D. C. Buller

Departure from radial flow in an homogenous, isotropic medium

Skin factor, as originally derived, is related to the departure from radial flow in an homogeneous, isotropic medium. A positive skin may arise from a reduction of the area available to flow and/or a departure from purely radial flow. This could be caused by anisotropy (typically by bedding so that horizontal and vertical permeabilities differ) or heterogeneity. Tariq et al. (1985) have presented an analysis of the effect of heterogeneity. Whilst large scale heterogeneity can cause a skin effect, the scale of heterogeneity which affects well productivity normally ranges from a dimension which is approximately of the order of a wellbore diameter, and ranges up to one or two orders of magnitude greater (Harper & Moftah, 1985). Examples are open and filled natural fractures, continuous or discontinuous shale stringers, local cementation or inclusions such as clasts or cobbles. Such heterogeneities should be evident in core, provided they are penetrated.

Mechanical deformation around a borehole or perforation tunnel

Erosion of the wellbore during drilling leads to an excessively thick cement sheath in the resulting out-of-gauge hole. This limits or precludes penetration of perforation tunnels into the reservoir, and increases the volume of cement filtrate (which may be incompatible with the reservoir rock). The development of out-of-gauge holes is a function of rock strength, drill string behaviour, mud characteristics, drilling time and in situ stress state.

Positive skins may also be generated by the creation of a crush zone around a perforation. When a jet produced by a shaped charge perforator enters the reservoir rock, the rock is displaced to one side of the jet. Crushing occurs in some rocks, forming a zone of low permeability around the perforation tunnel.

Both wellbore enlargement and perforation crush zone formation are purely or primarily a mechanical form of formation damage. They are well known. There is, however, an additional mechanical factor which does not appear to have been recognized previously as a potential cause of formation damage. Around any opening, such as a weUbore or perforation tunnel, the deviatoric stresses in a reservoir are concentrated so that local increases of stress difference occur. This may result in failure, giving rise to wellbore breakouts or sand production, in which case there exist some volumes of the material which have not failed but where conditions are close to failure. Microcracking and high levels of distortional strain must be expected in the vicinity of grain contacts in such zones of stress concentration. It is expected that microcracking may result in a permeability enhancement, but concentrations of distortional strain (and also, possibly to a lesser extent, hydrostatic strain) might promote fines release and permeability reduction.

Some preliminary experiments have been conducted to assess whether this expectation can be supported by laboratory data and whether a more rigorous evaluation is warranted. Reservoir core samples were flow tested with brine at room temperature and incrementally removed from the permeameter and subjected to a stress difference for a convenient period (twelve hours or less) before reloading and continuation of the flow testing. The results were inconclusive, samples showing both increase, decrease, and no change in permeability. Fig. 4 shows an example where permeability decrease appears to show some correlation with exposure of the core to a stress difference. Initially, the core was flow tested in unconfined conditions. Stresses of I000 p.s.i. (radial) and 4000 p.s.i. (axial and bedding-parallel) were then applied, followed by another period of flow testing, a period of

A a E

v >- k-

.d

<C LU

n- UJ 0.

1 7 5 -

1 7 0 -

1 5 0 -

1 4 5 .

Formation damage and remedial stimulation

T E S T F L U I D : 5% N a C I

EFFECTIVE STRESS DIFFERENCE

1. 3 0 0 0 psi ( 2 0 . 7 MPa)

2. 7 0 0 0 ps i ( 4 8 . 3 MPa)

++

2 4'

�9 " " I I I I I

so 100 150 200 2so

FLOW VOLUME. ml x 103

FIG. 4. Effect of stress difference on the permeability of a North Sea reservoir core.

741

loading at 1000 and 8000 p.s.i., more flow testing, and finally 1000 p.s.i, and 11 700 p.s.i. at which the sample failed. Overall, the results from the pilot test p rogramme were sufficiently supportive of the expected influence of deviatoric stress that a more rigorous series of tests has been planned.

Near-wellbore permeability reduction associated with production operations

A reduction of pressure (and also temperature) is associated with flow to a well. In the reservoir, this occurs primarily within the near-wellbore region. Associated with this are well-known adverse effects which can cause well productivity impairment, including the formation of gas blocks or liquid blocks, waxing, scale deposition, deposition of

742 T. R. Harper and D. C. Buller

asphaltenes and fines migration. The pressure drop may not be entirely detrimental, however, as the Mohr stress circle is displaced away from the rock failure envelope as the pore pressure around openings is reduced during production.

S O U R C E S OF I N F O R M A T I O N A V A I L A B L E F O R D A M A G E D I A G N O S I S/PROGNOSIS

In view of the preceding discussion, it is evident that many different aspects of geology and engineering influence well productivity. The petrology, including the diagenetic mineral assemblage, is one aspect, but there are many others which we believe must equally be considered if one is to optimize the chances of diagnosing or prognosing well problems. The sources of information upon which such diagnosis can be based are listed below with brief comments on each. Normally, only some of these data are available, or records are ambiguous. The ideal situation, in terms of the extent of information available to the formation damage analyst, rarely if ever pertains. Consequently, a considerable degree of interpretation and judgement is usually required of the analyst.

Drilling, completion and workover records

These represent the basic record of engineering operations. They form a basis for the initial identification of possible problems (e.g. drilling difficulties, use of loss agents, nature of perforation, dirty kill fluid). They also provide the framework for designing laboratory tests to assess potential damage (e.g. fluid/rock compatibility, fluid/fluid compatibility).

Well tests

Pressure transient analysis is the conventional oil industry method for identifying any impairment of well productivity, which is conventionally quantified in terms of a skin factor. As such, well tests are the cornerstone of the information available not only to detect formation damage, but to quantify the effect. In addition, the productivity index of a well (or, alternatively, injectivity index), measured during a period of flow, is a clear measure of well performance, and incorporates the skin factor.

Open hole or production logs

Wireline logs in the open hole can be used to indicate such features as out-of-gauge wellbores and wellbore breakout, fluid invasion depth, stratigraphy, and natural fractures. Commonly available, they can be used to check for potential problems such as an oversize cement sheath. Cased hole logs can be used to some extent to detect flow distribution after a stimulation treatment, and other factors relating to well performance such as the cement bond (poor cement jobs may give rise to positive skins because of crossflow behind the casing).

Production records

Trends of production performance may give clues to progressive changes associated with damaging processes such as waxing or scaling, or to the effects of workovers.

Formation damage and remed&l stimulation 743

Reservoir petrology

Petrological studies provide a basic description of the porous rock morphology and mineral content. These must be related to the engineering performance of the rock if the description is to adopt a more positive role than that of pertinent background information. While the factors governing the relationship between the type, content, morphology and distribution of minerals in an argillaceous material and response of that porous medium to fluid flow and changes of pore-fluid electrochemistry have not been defined, the potential value of a petrological description is necessarily limited. Many authors have attempted to classify formation damage potential on the basis of petrological descriptions (e.g., most recently, Basan, 1985). We regard such proposals as speculative until supported by the results of laboratory flow investigations.

Detailed reservoir structure

Whilst open fractures are known to assist well productivity, and are associated with negative skin factors, it is less well known that filled fractures can give rise to a positive skin (Harper & Moftah, 1985). This is sometimes termed a 'pseudoskin', which may be mistaken for formation damage induced by another process.

Sedimentary features of the reservoir

A positive skin may result simply from the layering associated with sedimentation. Either unequal bedding-parallel and bedding-normal permeabilities, or the influence of low permeability layers on flow to the perforations, may be responsible. Heterogeneities of the sedimentary sequence other than the latter can also give rise to positive skin factors.

Mechanical tests of core samples

Rock mechanical tests can sometimes be of value, such as to assess rock strength when wellbore enlargement is suspected, or strength reduction after acidizing a core. A variety of mechanical property indexing methods are available. Use of a hardness value has the merit of requiring only small test samples. Table 1 shows a sample of such results obtained after

TABLE 1. An example of the effect of mud acid on the mechanica l character is t ics

of an argi l laceous sandstone.

Trea tment

Mean dis tance from Approx imate strength

core inlet face Hardness reduct ion

cm (p.s.i.) %

Untrea ted - - 5000 - - Untrea ted - - 4200 - -

Acidized 1 1200 76

Acidized 3 3800 23 Acidized 5 3500 29

Acidized 7 5300 0 Acidized 9 5200 0

744 T. R. Harper and D. C. Buller

treating a core plug with mud acid (12% HC1, 3% HF). This core included calcite and dolomite cements, illite, chlorite, serpentinite and smectite-rich clay.

Character&t&s of reservoir fluids

Incompatibility between reservoir fluids and fluids or solids introduced by engineering operations can adversely affect flow, such as the sample shown in Fig. 3. If the chemistry of fluids is known, predictions of probable behaviour can be made. Knowledge of the reservoir fluids is also necessary to assess the potential for scale, wax, asphaltene formation or the formation of another phase (e.g. gas blocks in crude oils in reservoirs close to the bubble point).

Fluid-fluid interaction tests

Predictions of incompatibility can be checked by laboratory mixing tests. However, relating the results to field behaviour may not be straightforward.

Routine and special core analysis

Differences between core tests conducted at standard temperature and pressure and those conducted at reservoir conditions are often observed. For this and other reasons, routine core analysis is of limited application in diagnostic investigations of formation damage. Reservoir-condition tests, if conducted with sufficient care, are a critical source of information. However, because preserved core is not identical to virgin reservoir rock, interpretation may not be straightforward. Moreover, extrapolation from a limited number of core tests to well behaviour demands caution in heterogeneous reservoirs.

Other laboratory results, such as wettability or pore size distribution, normally provide valuable input to damage studies. Aside from tests, basic core description, which is orientated towards mechanisms which may cause damage, is essential.

Fluid-rock interaction

Because knowledge of the relationships between the visual and chemical petrology and the fluid flow characteristics of the medium is currently incomplete and ill-defined, the empirical approach of flow testing is critical to formation damage investigations. As with other techniques, this method is limited, in this case by availability of core and by disturbance to the core prior to testing. Moreover, the duration of a test programme is usually not insubstantial in relation to the time scales of exploration and production activities. As noted in the preceding paragraph, it is appropriate to perform tests at reservoir conditions.

A C A S E H I S T O R Y O F F O R M A T I O N D A M A G E D I A G N O S I S

Harper & Moftah (1985) reported a formation damage investigation in the Nubian Sandstone of the Ras Budran reservoir. All of the sources of information noted in the preceding section were employed in the diagnosis of formation damage.

Formation damage and remedial stimulation 745

The purpose of discussing this investigation in the present context is to illustrate some of the misleading conclusions which might have been drawn had not a sufficiently diverse bank of data been used, and the reader is referred to the cited publication for details of the overall programme.

Skin damage was noted in well tests to be restricted to the lower reservoir horizons at Ras Budran (Fig. 5). The reservoir rock is an approximately 20 md, normally-pressured, porous quartz-sandstone with pore-tilling kaolinite (Fig. 6). It is medium-grained, with moderately well-sorted and typically sub-rounded grains of which >98% are quartz. Two cements are present: quartz, and authigenic kaolinite occurring in typical 'book' form and comprising ~5% of the rock. Quantities of other clays are insignificant. Very thin, filled fractures are evident in core.

DEPTH

FT(M) TVSS

1 1 , 0 0 0 - -

3500 1 1 , 5 0 0 J

1 2 , 0 0 0 -

3750

1 2 , 5 0 0

[ ]

I i I I I I I 0 4 8 12 16 2 0 2 4

SKIN F A C T O R

FIG. 5. Variation of skin factor with depth,

UNIT 111" �9

UNIT 1I �9

UNIT I 121

[] []

Early in the investigation, the possibility that the observed skin factors were an artifact of the well test analysis resulting from partial penetration, rather than a damaging process, was considered. However, additional sedimentological study finally eliminated this possibility by identifying shale horizons extending across the reservoir, which are assumed to prevent any vertical communication and consequent partial penetration effect.

Damage incurred by kaolinite migration was suggested at the outset as a candidate damage mechanism, and considerable effort was expended to test this postulation. The results of a series of reservoir-condition core flow tests eventually eliminated this possibility. However, mud acid was found to increase core permeability by a factor of 20 or more.

On the basis Of the well data then available, a correspondence between apparent skin damage and the use of oil-based drilling mud, rather than seawater-based mud, was

746 T. R. Harper and D. C. Buller

Fro. 6. Pore-tilling kaolinite in Nubian Sandstone.

observed. Consideration of any changes of reservoir wettability from an assumed water-wet condition by liberation of previously immobile water around the wellbore and water-trapping, caused by oil-wetting surfactants in the drilling mud, was prompted by the observed correlation. Special core analysis tests, both conventional and innovative, were required before it could be concluded that this phenomenon was unlikely to be responsible for the observed skin damage. Innovative tests were in part required because the history of core recovery and accompanying processes were recognized as a possible influence on the results of conventional special core analysis.

Checks on compatibility of reservoir fluids and drilling/completion materials revealed an incompatibility of formation water and lost circulation material (LCM) used during drilling (Fig. 3). However, drilling records revealed that use of the LCM had been localized such that the inferred damage could not be attributed to this (although use of this agent was subsequently discontinued).

Formation of strontium sulphate scale where water-based mud was used was predicted on the basis of the chemistry of seawater and the formation water. Laboratory mixing correspondingly resulted in the formation of a white precipitate. However, this possibility was subsequently dismissed on the basis of the lack of correlation of high skin factors and use of water-based mud. Moreover, drilling and completion records revealed that one well had been suspended for several years with seawater-based fluid in contact with the formation, yet subsequent tests revealed negligibly small positive skin factors in this well.

Hole deviation correlated with apparent damage. However, wireline logs revealed that the possibility that out-of-gauge wellbores had formed during deviated drilling could be rejected.

Formation damage and remedial stimulation 747

FIG. 7. Thin-section of filled fracture.

The filled fractures (Fig. 7), generally of one or a few grain diameters, had a permeability very much less than that of the surrounding matrix. Because of the orientation of these small-scale structures relative to the core plugs tested in the laboratory, their influence was not detected by routine core analysis. From tests devised specifically to assess the influence of these features, it was determined that they are effective barriers to fluid flow. However, fracture continuity and orientation could not be determined from the unorientated, available core.

Rejection of all conventional mechanisms of formation damage, achieved only by using wide sources of information, compelled a close examination of the potential influence of a network of low permeability fractures distributed throughout the reservoir. Could these structures by some means cause excessive pressure loss in the volume of rock in the near-wellbore region? From this analysis it was concluded, on a qualitative basis, that an apparent local (near-wellbore) positive skin effect could be caused by a pervasive network or low permeability inclusions, such as those seen in core, for the following reasons: (i) the area available for flow to the wellbore/perforations is decreased; (ii) the path length is increased in the vicinity of the weUbore.

748 T. R. Harper and D. C. Buller

Alternative completion options were proposed on the basis of these conclusions. Despite the laboratory core observations, use of mud acid was rejected as useless in the presence of the low permeability fractures which contained little or no kaolinite. Not only does acid tend to spend on high-surface-area clays in preference to quartz, but the problems of diversion encountered in placing the treatment were not considered trivial. Therefore, the proposed completion philosophy markedly differed from that which might have been adopted had the major permeability increases seen in laboratory core acidizing been accepted without additional investigation.

S T I M U L A T I O N OF W E L L S I N T E R S E C T I N G N A T U R A L F R A C T U R E S

With decrease of reservoir quality, the significance of any natural fractures to the production process increases as the ratio of kJk increases, where k = formation permeability and ki = equivalent permeability of~the fracture. In many reservoirs, the number of perforation/fracture intersections is limited. If much of the production is channelled to the wellbore via these few intersections, then it is critical that these are clear of any plugging material (Murphy & Pearce, 1980). Such plugging material may comprise invaded drill solids (Kasperskii & Panov, 1971). Alternatively, patchy development of diagenetic fracture filling could cause near-wellbore plugging. The options for stimulation are primarily hydraulic fracturing and chemical treatments, usually acidizing. Hydraulic fracturing of naturally fractured reservoirs is not well understood, and may require the undesirable use of fluid-loss additive to control leak-off to the fractures. For reasons also of economy, chemical stimulation may appear to be a more attractive option.

Most natural fractures are of irregular aperture. Flowrate in a fracture can be approximated by parallel-plate relationships, i.e. flowrate is proportional to the cube of aperture. Consequently, the invasion of drilling fluid (slurry) into a fracture of irregular aperture can be envisaged as a sequential filling of channels of successively decreasing aperture until complete sealing around the wellbore intersection is achieved. Unfortunately, the aforementioned power law relationship which assists the sealing process also predicts that clean-up of the plugging material requires special precautions. Assuming that the acid dissolution front is irregular (because of variability of fracture aperture, irregular distribution of plugging material about the perforation or other reasons), breakthrough of acid to the region of open fracture will not occur uniformly, and a localized channel leading from perforation tunnel to open fracture will first be formed. The resistance to flow of acid offered by the open channel will usually be far less than the resistance offered by the porous plugging material (by close analogy with the subsequent analysis). In this case, progressive enlargement of the channel may be expected, with a rapidly decreasing flow of acid in the fracture plugging material and a rapidly increasing flow in the channel approximately according to the above power law.

The necessity for use of a diverting agent is therefore apparent. Use of ball sealers would in this case merely leave the fractures ineffectually producing hydrocarbon via a narrow channel connecting the open fracture system to the perforation tunnel. Diversion within the fracture is required if the acid is to continue to remove plugging material other than in the immediate vicinity of the channel (or channels) which are the first to form.

Candidate diverting agents could include gels, foams, or slurries which typically include

Formation damage and remedial stimulation 749

particulate salt, benzoic acid flakes or soluble resin particles. Carathers et al. (1984) have suggested the use of polymer gel for this purpose.

In order to assess the likely efficacy of linear gels as 'in-fracture' diverting agents, an idealized model was developed. A fracture is assumed to be plugged by an acid-soluble porous medium. This porous medium can be envisaged to be either drill-or-kill fluid solids, or a volume of porous diagenetic fracture filling. It is simply termed fracture plugging material (FPM). The following sequence of events in a gas well is envisaged:

(1) An initial acid stage results in an approximately uniform removal of FPM around the perforation tunnel, which is assumed to intersect the fracture orthogonally at the centre of the plugged region. Breakthrough of acid by a single channel is assumed. Acid then flows preferentially down the single channel, enlarging the channel with correspondingly decreasing radial flow velocity in the FPM, the majority of which remains untreated.

(2) A linear gel stage is injected. Flow is restricted to the channel. (3) A second acid stage is commenced. At this stage of development, the conceptual

model is as in Fig. 8. Additional assumptions include the use of parallel plate relationships to describe flow in the open channel, and that the fracture does not open or close in response to any stress changes. Referring to Fig. 8, the relative flow rate of acid in the porous medium (FPM) and of the acid-gel interface in the channel may be compared by considering the point at which the second acid stage has flowed to a radial

OPEN FRACTURE D

PLUGGED FRACTURE [ ]

FlG. 8. Idealizedcond~ionsassumedtope~ainduringacidizingofblock~ natural~acturea~er em~acemem ~agelp|uginchannelopenedbyadd.

750 T. R. Harper and D. C. Buller

distance r 1 from the perforation tunnel. Relationships given by utilized (oilfield units).

For flow of acid in the FPM:

Muskat (1946) are

k Pl - P 2 Valr=r ---- rl//a In rz/r ~

For flow of gel in the channel:

kl ( P ~ - P 2 ) 10a ez ( P l - P 2 ) . . . . = - - .

/tg ( r 2 - r l ) 12#g ( r 2 - r 1)

where e, the fracture aperture, is measured in cm, fla and/~g are the viscosities of acid and gel respectively, and V a and Vg the respective flow velocities. Thus:

Va -- 1.2 • 10 -7 k /~g r 2 - r 1 Vg e2 "l~a rl In (r2/rl)

Typical values can be used to demonstrate that the acid flowrate in the plugging material is negligibly slow compared to the rate at which the gel plug is 'extruded' from the channel. For example, i fk = ! mD, e = 0.1 cm, #g = 200 cp and/~ a = 1 cp, then:

r 2 - - r 1 Va/V , = 2-4 x 10 -6

r I In (rz/r 0 "

This idealized model therefore strongly suggests that use of a gel (or foam) as an in-fracture diverting agent is unlikely to permit effective removal of plugging material around the perforation tunnel. The value of linear gels as diverting agents in fractured reservoirs may therefore be restricted to diversion from one path to another in open fracture systems.

C O N C L U S I O N S

Engineering tests are normally required to assess engineering performance, and the prognosis or diagnosis of formation damage is no exception. In the absence of such tests, and without the use of all available data encompassing both geological and engineering activities, conclusions must be treated with an appropriate degree of caution.

It is proposed that failure on the microscopic scale, occurring in rock which has not failed on the macroscopic scale, can be a cause of formation damage. The nature, significance and sense of permeability change (increase or decrease) associated with this process has yet to be established.

Acid stimulation designs are normally based upon the assumption of porous media flow. This approach is shown to be inadequate in fractured reservoirs, where acid treatments may more critically influence well productivity than in porous media. Diversion within a fracture is necessary, and analysis has indicated that viscous linear gel stages are inadequate for this purpose if the intention of the treatment is to remove porous filling material.

Formation damage and remedial stimulation 751

A C K N O W L E D G M E N T S

The authors are grateful to J. Hyatt and S. Bishop for the reported laboratory results, and to Mr J. F. Berry for informative discussion. We are pleased to acknowledge the support and encouragement given by the British Petroleum Company.

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