Clay Minerals (1986) 21,~769-780

THE R O L E OF D I A G E N E T I C S T U D I E S IN P R O D U C T I O N O P E R A T I O N S

J . D . K A N T O R O W I C Z , L . L I E V A A R T , J. G . R . E Y L A N D E R AND M. R . P . E I G N E R

Koninklijke/Shell Exploratie en Produktie Laboratorium, Volmerlaan 6, 2288 GD, Rijswijk, The Netherlands

(Received 13 May 1985; revised 14 November 1985)

A B S T R A C T : Petrographical studies can be undertaken to investigate the effects of production operations on sandstone reservoirs and to identify the nature of any rock-fluid interaction. In combination with diagenetic models the results may be employed to predict the effects of field development programmes on reservoir mineralogy, and to avoid costly damage to the reservoir's permeability. Acidization to remove drilling mud from Reservoir A samples was undertaken in two stages to avoid adverse rock-fluid interaction. HC1 dissolved siderite and chlorite but did not increase permeability. This is because the dissolved siderite released previously cemented clay particles into the pore space. A subsequent mixture of HCI and HF dissolved all the clays present in the treated area including the drilling mud, but also etched the quartz cement. Permeabifity increased significantly but the rock's strength decreased. This could cause an influx of loose sand during hydrocarbon production. Water injection into Reservoir B samples caused a variety of rock-fluid interactions. In finer-grained samples movement of siderite rhombs as well as clay particles blocked pores, and changes in porewater composition caused smectite to swell. Both effects caused permeability to decline. In the coarser-grained siderite-free samples, permeability improved after oil and clay particles had been displaced. In the reservoir these effects would combine to exacerbate the effects of the existing reservoir heterogeneity. Steam injection into Reservoir C samples caused mineralogical reactions. Amounts of dolomite and kaolinite decreased, and smectite and calcite were generated. This may affect the permeability of the reservoir and will determine whether oil can be produced through the affected sediment.

In order to recover hydrocarbons from oil and gas fields, a number of appraisal and develop- ment wells may need to be drilled. The posit ion of these wells, and whether they are to produce hydrocarbons or to inject gas or water or various chemicals, depends on how the field is to be developed. Product ion that results from 'natura l drive energy' (the expansion of the compressed hydrocarbons in the reservoir or water influx from a highly pressured

aquifer), is termed ' p r imary recovery' . This natural drive energy can be supplemented by in- jection of water or gas in what is termed ' secondary recovery ' . After pr imary and second- a ry processes, the remaining or residual oil may be recovered by enhanced oil recovery processes. These involve heating the oil to lower its viscosity, or changing the propert ies of either the injection water or the oil to allow residual oil to be displaced more easily. Thus, field development involves product ion operat ions such as drilling, producing hydrocarbons

and injecting water, all o f which will upset the equilibrium that exists in the reservoir between the formation and its pore-fluids. The term ' rock-f lu id interaction' may be used to describe the changes in reservoir characterist ics such as porosi ty and permeabil i ty that occur in response to field development. One pract ical ly unavoidable consequence of

�9 1986 The Mineralogical Society

770 J. D. Kantorowicz et al.

rock-fluid interaction during most production operations is a reduction in permeability. This is termed 'formation damage' and may result from mineral reactions and precipitation, and plugging by introduction or indigenous solid particles (Maly, 1976). Formation damage may also occur as a result of changes in the relative permeabilities,of oil and water caused by changes in wetting. Acid and fracture stimulation are two specific production operations designed to improve individual well performance, although in certain circumstances these too can lead to formation damage.

The purpose of this paper is to present the geological aspects of three laboratory investigations into rock-fluid interaction. The effects discussed are based on an assessment of samples before and after the respective laboratory tests. These examples are not necessarily typical of reservoir response to the three production operations in question, but serve to illustrate the variety and complexity of rock-fluid interaction. They suggest that clays are not the only minerals to play a significant part in rock-fluid interaction, and illustrate the need to investigate every aspect of a reservoir's petrography and diagenesis.

T H E P U R P O S E OF P E T R O G R A P H Y A N D D I A G E N E T I C S T U D I E S

A variety of analytical techniques may be applied to establish the distribution of minerals in a cored interval. This information can be used for different purposes. First, in isolation, and without any knowledge of the origin of the mineral constituents, core information may lead to an understanding of, for example, the reservoir's response to acid stimulation. This is because certain production operations may only require a knowledge of the mineralogy immediately adjacent to the well and this is likely to be represented by a recovered core. However, the damage that can occur around a well is often a result of its drilling and completion (the latter involving such processes as gravel packing or cementing casing into the well and perforating it with explosive charges). Consequently, damage often occurs before core information from the same well becomes available. Besides which, it is not practical to core all the wells in a development programme. Secondly, in contrast to the acids injected to remove near-wellbore damage caused by drilling mud or completion fluids, chemicals injected during enhanced oil recovery processes are required to operate effectively while contacting large volumes of rock over the entire distance between the injection well and the production wells. Planning to ensure efficient oil recovery therefore necessitates detailed knowledge of the mineralogy throughout the reservoir at an early stage of the development programme. Combined with an understanding of each individual mineral's influence on rock-fluid interaction this allows the effect of upsetting the reservoir-pore-fluid equilibrium to be assessed.

In order to predict the composition of the reservoir, and the distribution of its minerals, it is necessary to establish a sedimentological and a diagenetic model. Predictions of reservoir mineralogy cannot be made on mineral identifications alone. First, quantitative petrographical analysis should be undertaken to identify the texture and mineralogy, the origin of the minerals and their distribution. Once detrital and authigenic components have been distinguished, a diagenetic model can be established and used as a basis for predicting authigenic mineral distribution throughout the reservoir. The distribution of detrital minerals can be predicted on the basis of the sediment's texture and hence the sedimentological model. By combining these models it should be possible to predict the mineralogy that any new well is likely to encounter, and to ensure that, for example, the drilling fluid composition is tailored to minimize formation damage.

Diagenetic studies and produetion operations 771

FIG. 1. (a) General thin-section photomicrograph of the reference sample prior to acid stimulation. Well-sorted, fine-grained sandstone with little cement and only loosely packed grains. Grain surfaces are coated with iron-stained clay in places. Porosity is entirely intergranular with few open pore throats. Minor pore-filling calcite and siderite cement occurs. Plane polarized light. Field of view 2 mm across. (b) General thin-section photomicrograph of the mud-acid-treated sample. Moderately well-sorted area of the sample where grain size ranges from coarse silt to fine sand. No cement occurs. Grain contacts are mostly points. Compared to (a) increased porosity is apparent. Also, the style of porosity has changed, with a significant

amount of grain dissolution porosity evident. Plane polarized light. Field of view 2 ram.

772 J . D . Kantorowicz et al.

A C I D S T I M U L A T I O N

Drilling mud is used to lubricate the drill bit, to lift cuttings from the hole, and to contain formation fluids. The drilling mud, usually comprising particles of smectite and weighted with baryte, is designed to form a filtercake on the formation face, thus minimizing mud leak-off and hence mud invasion into the formation. Efficient perforating will penetrate the filtercake but acid stimulation frequently is undertaken to remove the damage created by the invaded drilling mud, and hence to restore or possibly enhance the original permeability of the rock in the damaged zone. The acid used for this purpose is usually mud acid, a mixture of 7.5% HC1 and 2.5% HF. However, since the acids used to remove damage in the near-wellbore area are all pumped into the formation, they will also come into contact with the formation itself.

Core samples from Reservoir A were investigated to assess the effect of acid stimulation on the formation. Samples were routinely examined before the core-flooding programme to establish the original mineralogy. The reservoir comprises very fine grained quartz-arenites, with a small percentage of rock fragments and feldspars as well as sporadic foraminifera (Fig. 1). The sands are texturally mature, porous and partially lithified with siderite and a thin veneer of quartz overgrowths (Fig. 2). Discrete pore-filling siderite rhombs also cement and enclose silt-sized quartz grains and detrital clay particles. Porosity is further reduced by irregularly distributed authigenic grain-coating chlorite and more evenly distributed detrital clay. Chlorite, kaolinite, illite and mixed-layer illite-smectite were identified by XRD. Siderite comprises 5-10% of most samples, clay 2-5%, and the clay fraction includes 10% kaolinite, 40% illite, 30% chlorite and 20% mixed-layer illite-smectite. The diagenetic model for these samples suggested that similar minerals could be expected throughout the reservoir.

On the basis of the mineralogy several likely causes of deleterious side effects during acidization were identified. These include iron-bearing minerals (siderite and chlorite), and 'fines'--silt-size quartz grains and clay particles (Figs la, 2a). Although carbonates are readily soluble in hydrofluoric acid, insoluble salts such as CaF 2 are likely to precipitate and thus plug the newly created porosity (Williams et al., 1979). This is also true of siderite because pure FeCO 3 is only rarely found. Substitution of Ca z§ and Mg 2§ for up to 50% of the Fe 2§ can occur. Similarly, dissolution of iron-bearing minerals may lead to the precipitation of iron oxides and hydroxides, commonly known as 'iron gel', if the pH is allowed to rise, or if Fe z+ is oxidized to Fe 3+. Fines in the formation will behave in the same manner as the drilling mud particles, potentially blocking pores when mobilized during production or injection. Consequently, the stimulation programme includes HC1 injected ahead of the mud acid as a 'preflush' to remove the carbonates and so prevent fluoride salts precipitating, iron sequestering agents to prevent iron gel formation, and sufficient mud acid to remove the drilling damage. It should be pointed out that acid stimulation programmes should always include iron sequestering agents to prevent gel formation by iron and rust picked up from the tubing. Also, acids may be back-produced before the pH has increased to prevent precipitation of residual silica and alumina gels. Alternatively they are overdisplaced into the formation to prevent precipitates forming in the near-wellbore area, where they could cause significant reductions in productivity or injectivity.

The response to the acid stimulation programme involving a hydrochloric acid preflush and then mud acid is illustrated schematically in Fig. 3. After HC1 treatment, siderite and chlorite were absent and porosity increased slightly. However, abundant silt and clay-sized material remained and permeability was little changed. Indeed, dissolution of cementing

Diagenetic studies and production operations 773

FIG. 2. (a) Scanning electron micrograph of the reference sample illustrating a thin veneer of quartz cement on a detrital quartz grain, Quartz encloses grain-coating chlorite in places. However, poorly developed quartz is the only cementing mineral in this rock. Scale bar 10 #m. (b) Scanning electron micrograph of the acid-treated sample. Clays are not present in the sample and euhedral quartz overgrowths are no longer visible. With energy-dispersive analysis the etched stumps were seen to contain only silica and probably represent former euhedral

overgrowths. Scale bar 10 gm.

774 J.D. Kantorowicz et al.

PERMEABILITY

/0~0 --X--X--X--X

/ o/

~X--X--X-- --o--o--o--o--x~x--X j

NH4CI HCI NH4CI HCI/HF NH4CI

I

PORE VOLUMES

FIG. 3. Graphical summary of acid flooding tests on core samples of Reservoir A. Permeability was not affected by HC1 flushing but was significantly improved with mud-acid treatment.

carbonates released fine clays and silt-sized quartz grains into the pore space. This countered any improvement in permeability that might have been expected from dissolving the carbonates themselves. It follows that carbonate cements had little control on permeability. The effect of mud acid treatment was more pronounced, with all the clays, silt-sized grains and feldspar grains present originally being removed, and quartz overgrowths being partially dissolved (Figs lb, 2b). Also porosity and permeability increased, the latter by 25%. The only drawback to this otherwise successful stimulation was revealed during SEM examination of the samples. After mud acid treatment, quartz overgrowths were observed to be etched or corroded and the proportion of floating grains and loosely packed grains had increased (see Appendix A). BrineU Hardness Tests (van der Vlis, 1970) confirmed that a significant reduction in rock strength had occurred. After testing, much of the original core material comprised loose quartz grains. Although during acid stimulation the zone of reduced strength will be restricted to the near wellbore area, this could lead to some sand production after the stimulation programme.

W A T E R I N J E C T I O N

Water is injected into reservoirs during secondary recovery to maintain reservoir pressure and to sweep hydrocarbons towards producing wells. Core samples from Reservoir B were flooded with the proposed injection water to evaluate the formation's response both to the injection-water chemistry and to the proposed rate of injection. Core-flooding tests should address both these aspects as it is well established that both can lead to a reduction in permeability during water injection. Permanent impairment resulting from a change in porewater chemistry is referred to as 'static impairment' or 'chemical shock'. Impairment that results from fines mobilization is referred to as 'dynamic impairment' and during core-flooding tests is temporarily reversible. The conditions at which dynamic impairment occurs may also depend on the rate of change in porewater chemistry (Khilar & Fogler, 1983). The tests were run on preserved cores containing the original reservoir hydrocarbons to simulate water injection into these oil-bearing sands.

Diagenetie studies and production operations 775

FIG. 4. (a) Thin-section photomicrograph of a well-sorted sample from Reservoir B. In the field of view part of the sample is porous and uncemented, the remainder cemented with siderite. Plane polarized light. Field of view 2.5 mm. (b) Scanning electron micrograph of a well-sorted sample from Reservoir B. The sample comprises medium- to sporadically fine-grained sand with pore throats up to 60/~m wide. Scattered clay particles are significantly smaller than the pore

throats. Scale bar 100pm.

776 J. D. Kantorowicz et al.

Jf

500~

Ethylene Glycol

Air dried

I Y I I ]

Degrees 2e 15 12.8 93 6.5 5.5 2

d spacing ,~ 7 10 14 17

FIG. 5. XRD traces of the air-dried, glycolated and heated clay fraction. The sample includes illite (10 A), mixed-layer illite-vermiculite 10-12 A), kaolinite (7/~), chlorite 14 A, and smectite

(14 A expanding to 17 A with glycolation).

The reservoir comprises very-fine grained and poorly consolidated sandstones, exhibiting a wide range of textures, from mature and clay-free to poorly sorted and immature. Mineralogically, they are sublitharenites and arkosic sublitharenites. Thin-sections showed discrete, evenly distributed siderite rhombs, and small but significant quantities of clay (including authigenic kaolinite), some of which is cemented by siderite and loose silt-sized quartz grains (Fig. 4). The clay minerals include illite, smectite, kaolinite, chlorite, and mixed-layer illite-smectite and iUite-vermiculite (Fig. 5). However, no significant cemen-

Diagenetie studies and production operations 777

tation of the framework grains was observed. The diagenetic model for the samples suggested that similar minerals could be expected throughout the reservoir and hence any problems encountered here, particularly those related to water chemistry alone, could be expected to recur and affect the water injection programme. Similar effects could also be expected when injected waters reached production wells.

During core-flooding experiments various effects were observed. In some tests perme- ability to injection water declined by 20% (Fig. 6a). These experiments were repeated with the flow reversed, and permeability temporarily was restored to 90% of the initial perme- ability before again declining to 80% of the initial permeability. Two styles of impairment are recognized here: static impairment, which causes the permanent 10% decrease in permeability, and dynamic impairment which causes the temporarily reversible 10% permeability decline. To investigate further the likely causes of the impairment, unflushed plugs and both ends of the flushed plugs were examined by SEM but no significant differences were observed. The samples where impairment occurs are generally the more poorly sorted and finer grained. Consequently, the cause of the dynamic impairment is probably material that is mobile over short distances only. The fines include clay particles, 2-10 #m in diameter, siderite rhombs 10-20 /~m across, and silt-sized quartz grains 20-60/~m in diameter. However, pore throats within the samples are 20-40/tm in diameter. Any fines between one tenth and one third of the pore-throat diameter can interfere with each other during flow and can bridge and plug pore throats (Thomeer & Abrams, 1977). Dynamic permeability decline, therefore, can be attributed to mobile fines, but particularly to silt-sized quartz grains and siderite rhombs as well as clay particles.

Chemical shock can be attributed to hydration and expansion of smectite lattice cations causing swelling, or to osmotic swelling and clay particle dispersal (Van Olphen, 1977). The smectite and mixed-layer illite-smectite present are, therefore, responsible for the 10% static impairment; dispersed particles would only contribute to the dynamic impairment described above.

Chemical shock during injection is usually attributed to differences in water composition. Here there is a slight difference between the injection-water chemistry and the formation water. However, the injection water is more saline, and has a higher ratio of divalent to monovalent cations compared to the formation water. Under these conditions, both the physical swelling of clays, such as smectite, and the dispersal of discrete clay particles should be inhibited (Mungan, 1965; Lever & Dawe, 1984). Nevertheless, there is a difference in pH between the two and this can affect the activity of the various cations in solution and so cause the release of clay particles and clay swelling effects (Mungan, 1965).

In other tests from this reservoir the permeability declined initially (Fig. 6b). These samples, however, are generally better sorted than those in which permeability declined and contain few siderite rhombs. Also, pore-throat geometry significantly exceeds clay particle size. The behaviour of these plugs during core-flooding experiments can be related to both oil and water in the pores. Injection of water initially causes a permeability decline as oil is displaced and an oil bank builds up. Permeability drops because both oil and water are flowing. Subsequently, when the oil bank and any entrained fines are displaced from the rock and water is the only mobile phase, the permeability increases (Muecke, 1979).

In general, the effect of reducing permeability in less-permeable sandstones, and increasing permeability to water in the more permeable sandstones, will be to accentuate the original reservoir heterogeneity and consequently reduce the efficiency with which a water-flooding programme sweeps through the reservoir.

778

I 0 -

K Ki

J. D. Kantorowicz et al. FINES M[GRATION

FORWARD FLOW REVERSE FLOW

INJECTED VOLUME

I 0 -

K

Ki

/ PORE VOLUMES

FIG. 6. Schematic illustrations of the effect of fines in core-flooding tests. (a) Fine particle size exceeds pore-throat geometry, and permeability impairment occurs. Reversing the flow dislodges fines from pore throats and restores permeability until the fines accumulate elsewhere. (b) Fine particle size is less than pore-throat diameter and the rocks are water wet. An initial loss of permeability occurs as injected water dislodges oil but permeability increases as all the oil is displaced. The relative permeability to water increases as fines are flushed from the

c o r e .

S T E A M I N J E C T I O N

Steam injection is undertaken to mobilize residual oil remaining after water flooding or to mobilize heavy, and more viscous, crude oil which cannot be recovered by conventional processes. Injected steam, usually at 200-300~ both reduces the viscosity of the oil, by increasing its temperature, and causes light-ends to vapourize. The oil is thus more easily- displaced from the reservoir. When the steam condenses, a less viscous bank of oil is formed in front of the condensing zone and is displaced forwards as more steam is supplied. Steam is injected to enhance recovery in one of two ways. It may be injected into, and soak, a reservoir before being produced out through the same well (steam soaking), or

Diagenetic studies and production operations 779

it may be injected into one well and driven towards another well where the oil is produced (steam flooding).

Core samples from Reservoir C were investigated to assess the effect on the formation of steam injection at elevated temperatures. This study also enables the relative merits of steam flooding and steam soaking to be assessed. The sandstones of Reservoir C are fine- to medium-grained arkosic sublitharenites, All samples contain minor micaceous and illitic clays, kaolinite and dolomite. After steam treatment there was a marked increase in the proportion of smectite and an overall increase in the amount of clay. Slight decreases in amounts of most other minerals were also noted. Calcite was also observed in the samples after steam treatment although it was not present before. The overall effect of steam injection into these samples is to convert kaolinite and illitic clays, and framework minerals such as feldspars, into smectite. The cations required to convert kaolinite to smectite are derived from dolomite or feldspars, with calcite forming as a by-product.

Kaolinite + dolomite -* Mg-smectite + calcite

Kaolinite + Na-feldspar -, Na-smectite

These reactions are similar to those described elsewhere during steam injection into clay-rich sandstones, although no zeolites were observed in this study (cf. Hutcheon, 1984). It is not yet clear, however, whether the smectites are generated at injection temperatures or during cooling. The creation of smectite in the reservoir might result in a net rock volume increase, and could adversely affect permeability. Consequently, the effect of steam on the reservoir itself must be considered when assessing the practicality of various methods of enhanced oil recovery. In the case of steam-soaking much of the mobilized oil may be separated from the well by an interval of smectite-rich rock. The zone through which the oil must flow back may have reduced permeability. In a steam-flooding operation, by contrast, the mobilized oil is displaced ahead of the water and the newly formed minerals occur behind. In spite of reduced permeability, continued injection of low-viscosity steam will continue to displace the flood front. Newly formed minerals in the steam tongue may reduce permeability, and slow down and deflect the steam. This will thicken the steam tongue causing more stable displacement. Consequently, it is possible that while both steam-soaking and steam-flooding will improve recovery, the effect on the formation of the steam itself may be to reduce permeability.

C O N C L U S I O N S

The majority of reservoir rocks in the subsurface exist metastably in a diagenetic equilibrium with little potential for further natural reaction (or changes in petrophysical properties) during the life of a field development programme. Drilling through reservoir formations and either production or injection are likely to upset this balance. Many of the effects do not alter the mineralogy, but do change permeability. However, the dramatic changes of pore-fluid composition during acidization, or to a lesser extent, water injection, can cause changes in mineralogy. Similarly, changes in temperature during steam injection cause major changes in mineral composition and sediment texture.

The results of three laboratory tests are presented here, on the basis of which reservoir mineralogy and permeability may be expected to change during field application.

780 J. D. Kantorowicz et al.

These examples have been selected to illustrate the range of problems which can occur and to illustrate the importance of diagenetic studies in understanding reservoir performance and resolving production problems. In each case it is demonstrated that the specific cause can only be identified by a thorough petrographical examination of reservoir samples before and after pilot tests. Thus the role of petrography in production operations is to ensure that potentially damaging rock-fluid interaction is identified and if possible ensure that the style of damage is tailored to be less dramatic or more easily remedied. The role of diagenetic studies is to allow the effects of rock-fluid interaction in wells to be predicted and to allow field development programmes to proceed without causing any undesirable damage to the reservoir.

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

Shell Research Laboratories gave permission to publish this paper. Colleagues at KSEPL are thanked for their assistance with various aspects of this research and for helpful discussions. XRD analysis of Reservoir B was undertaken by Prof J. Thorez of Liege University, the figures were prepared by L. van Eijk, and the manuscript was typed by J. Aarden.

A P P E N D I X

It is believed that minerals may be dissolved in either of two ways. In one case the rate of dissolution and removal of ions from the dissolving mineral's surfaces depends upon the surface energy characteristics of the dissolving mineral. This is termed 'surface reaction controlled dissolution' and usually preserves the crystal morphology of the dissolving mineral. The other process is termed 'transport controlled dissolution'. In this case the rate of removal of ions from the dissolving minerals surface is dependent on the supply and flow of solvent to and from the dissolving surface. This process usually causes rounded textures and rarely preserves any morphological characteristics of the dissolving mineral's crystal form (Berner, 1978). To date, studies of quartz have suggested that its dissolution is surface reaction controlled. However, in this study when comparing the morphology of the anthigenic quartz before and after the acid treatment we observed a general rounding of the quartz faces, and the loss of distinct crystal edges. These features are all indicative of transport-controlled dissolution.

R E F E R E N C E S

BERNER R.A. (1978) Rate control of mineral dissolution under earth surface conditions. Am. J. Sci. 278, 1235-1252.

HUTCHEON I. (1984) A review of artificial diagenesis during thermally enhanced recovery Mere. Am. Assoc. Petrol. Geol. 37, 413-429.

KHILAR K.C. & FOGLER H.S. (1983) Water sensitivity of sandstones. Soe. Pet. Eng. J. 55-64. LEVER A. & DAWE R.A. (1984) Water-sensitivity and migration of fines in the Hopeman Sandstone. J. Petrol.

Geol. 7, 97-108. MALY G.P. (1976) Close attention to the smallest job details vital for minimising formation damage.

Proeeedings 2nd SPE Symposium on Formation Damage Control, Houston, Texas, SPE Paper 5702. MUECKE T.W. (1979) Formation fines and factors controlling their movement in porous media. Jr. Petrol Tech.

31, 144-150. MUNGAN N. (1965) Permeability reduction through changes in pH and salinity. J. Petrol Tech. 17,

1449-1453. OLPHEN H. VAN (1977) An Introduction to Clay Colloid Chemistry, 2nd edition. John Wiley and Sons,

318 pp. THOMEER J.H. & ABRAMS A. (1977) A shallow plugging-selective reentry technique for profile correction, J.

Petrol Tech. 29, 571-578. VLIS A.C. VAN DER (1970). Rock classification by a simple hardness test. Proc. 2nd Congr. Int. Soc.for Rock

Mechanics, 2, 1-8. WILLIAMS B.B., GmLEY J.L. & SCHECTER R.S. (1979) Acidising Fundamentals. Soc. Pet. Eng. AIME.

Monograph 6, 124 pp.