Effects of Depositional and Diagenetic Characteristics on Carbonate Reservoir Quality a Case Study From the South Pars Gas Field in The

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Eff ects of depositional and diagenetic characteristics on carbonatereservoir quality: a case study from the South Pars gas field in the

Persian Gulf

B. Esrafili-Dizaji and H. Rahimpour-Bonab*

Department of Geology, University of Tehran, Tehran, 14155-6455, Iran*Corresponding author (e-mail: [email protected])

ABSTRACT: The largest non-associated gas reserve of the world is hosted by theUpper Dalan–Kangan (Upper Khuff equivalent) Permo-Triassic carbonate– evaporite successions. Detailed characterization of these strata in the South Pars fieldhas shown that the reservoir properties are a function of both sedimentary anddiagenetic processes at the field scale. Facies analysis of the studied units indicates

that the sediments were deposited in the inner regions of a homoclinal carbonateramp and were subsequently subjected to shallow diagenesis and minor burial. The vertical distribution of the facies shows cyclic patterns that impact reservoirquality.

The rock type classes have been grouped on the basis of the dominant porespaces, and have enabled distinct fields to be identified. This approach hasdemonstrated a relationship between poroperm values and rock type groups.Diagenetic overprinting has significantly affected the reservoir properties.

Although the original poroperm heterogeneities in the studied reservoir areinherited from the Upper Dalan–Kangan palaeoplatform, they have been modifiedstrongly by diagenetic overprinting. Consequently, tentative correlation may bepossible between facies types and reservoir properties based on diagenetic effects. Therefore, for precise characterization of the Upper Dalan–Kangan reservoir

properties it has been necessary to integrate both the depositional history anddiagenetic features.

KEYWORDS: carbonate reservoir heterogeneity, diagenesis, Persian Gulf, South Pars field, Khu ff

reservoirs, Dalan and Kangan Formations

INTRODUCTION

Numerous giant gas and condensate fields have been discov-ered in the Persian Gulf Basin since the 1970s. Most of thesefields produce from the Permian Dalan and Triassic Kanganformations (Stratigraphic Committee of Iran 1976; Szabo &

Kheradpir 1978), or Khuff carbonates. According to ourestimates, this interval in the Persian Gulf states holds betweena quarter and a third of the total proven world gas reserves. Inthis gas prospective region, also known as the Khuff reservoirprovince, there are more than 80 non-associated gas fields. Theorganic-rich Silurian Hot Shale (Sarchahan Fm. and/or Qusaibamember) is considered the hydrocarbon source rock for thesereservoirs (Bordenave 2008).

The reservoir rocks are regionally extensive in the subsur-face Arabian plate and crop out in the Zagros Mountains,Central Arabian Arch, and the central and northern OmanMountains. This potential reservoir is still relatively under-explored in the Persian Gulf countries (Iran, Qatar, Bahrain,Saudi Arabia, United Arab Emirates, Oman and Kuwait).

Sediments tend to thicken northwards, away from the ArabianShelf, suggesting that there was a deep basin in the interior of

what is now Iran and a regional shallowing trend towards the west and SE of the Gulf ( Kashfi 1992). The impermeableanhydrite and shale succession of the Triassic Dashtak Forma-tion (and its lateral equivalent Sudair Formation) provides theseal for the reservoirs.

Gas and condensate in this petroleum system are trapped in:

(1) north-trending large, gentle anticlines formed from reacti- vated basement fault blocks (i.e. Qatar Arch); (2) salt domesthat resulted from halokinesis; or (3) the NW–SE trending structural traps that result from Zagros folding (Pollastro 2003;

Al-Jallal & Alsharhan 2005). The combination of these region-ally extensive, exceptional petroleum system elements (source,reservoir, seal and overburden rocks) and the formation of thelarge subtle structural closures prior to or contemporaneous

with the peak of gas generation and migration, have producedthese important gas fields (Pollastro 2003; Bordenave 2008).

The Upper Dalan–Kangan successions (Upper Khuff equivalent) host the giant gas reserve in the Qatar Archstructure. The northern extension of the Qatari North field (orNorth Dome) in Iran is known as the South Pars field (Fig. 1).

The North and South Pars fields were discovered in 1971 and1990, respectively and nearly 200 wells have been drilled there.

Petroleum Geoscience , Vol. 15 2009, pp. 325–344 1354-0793/09/$15.00 2009 EAGE/Geological Society of LondonDOI 10.1144/1354-079309-817



During the last four decades, following its discovery, thegeological parameters controlling reservoir quality and itscharacteristics have not been documented widely. There are nodetailed publications regarding the geology of the North Fieldin Qatar. However, published studies of the Iranian part of thisreservoir revealed that its rocks are extremely heterogeneous ona vertical scale (Ehrenberg 2006; Rahimpour-Bonab 2007;Rahimpour-Bonab et al . 2009).

The main aim of this study is to discuss the depositional anddiagenetic characteristics of these carbonate formations andtheir controls on the reservoir quality. The results of this study can be extended to the Qatari part (North Field). In addition,these results may affect the reservoir characterizations andpredictions in the other Khuff reservoirs elsewhere in thePersian Gulf Basin.

GEOLOGICAL SETTING

The Persian Gulf Basin comprises several NW–SE-trending geotectonic units, such as the Arabian Platform, and a zone of marginal troughs, including the Zagros Fold Belt, limited to theNE by the Main Zagros Reverse Fault (Edgell 1996). TheKhuff gas and Arab oil accumulations are situated in the Gulf Basin (Ehrenberg et al . 2007). This basin is one of the world’srichest oil and gas provinces, containing 55–68% of the world’srecoverable oil reserves and more than 40% of its gas reserves(Konyuhov & Maleki 2006).

Several important north–south structures, such as the majorQatar–Kazerun lineament (Qatar Arch), cross the region. Thegeological history, sedimentary formations and petroleumpotential of this basin have been reviewed by many authors

(e.g. Alsharhan & Nairn 1997; Pollastro 2003; Al-Jallal & Alsharhan 2005; Konyuhov & Maleki 2006).

Tectonic framework

Since the Infracambrian, a structural high – the Qatar Arch(QA) – has divided the Persian Gulf Basin into two troughs:the ESE and the WNW sub-basins. It was particularly promi-nent during the Infracambrian, Early Silurian, Late Permian,Late Triassic, Late Jurassic and Cenozoic (Murris 1980;

Alsharhan & Nairn 1997; Pollastro 2003; Bordenave 2008)(Fig. 2).

The QA, which is a NNE–SSW-trending structural high, hasbeen rejuvenated and uplifted repeatedly since the Infracam-

brian (Edgell 1996; Al-Husseini 2000) (Fig. 2). It is a regional,gentle and broad anticline or open periclinal structure whichhas had an important influence on the history of the Gulf (Alsharhan & Nairn 1997; Konyakhov & Maleki 2006).

The QA extension can be divided in two parts, the onshoreand offshore Fars provenance of the SE Zagros belt. Theonshore extension of the QA in the coastal Fars is known asthe Fars Platform. This platform is a structural high boundedby the Nezamabad (NZ) and Razak (RK) faults to the east and

west, respectively (Bahroudi & Talbot 2003). Some important fields, such as North Pars, Kangan, Nar, Aghar, Bandubast,Dalan, Asaluyeh, Shanul and Varavi, are among the 15 Dalan– Kangan gas fields in this area. In offshore Qatar, the North andSouth Pars fields are located on the NNE plunge of the Arch.

The eastern side is a gently dipping monocline; the western sideis bounded by faults (such as the Kazerun–Qatar fault) and aseries of steep-sided anticlines, which form the western limb of the structure (Alsharhan & Nairn 1997).

Fig. 1. Right: Location of the South Pars and North fields in the Persian Gulf Basin. The Upper Dalan–Kangan hosts the world’s largest gasreserve in these fields. Left: Location of some wells in these fields. This article focuses on information provided by ten boreholes of the SouthPars field.

B. Esrafili-Dizaji & H. Rahimpour-Bonab 326



Tectonic movements during the Late Precambrian–Early Cambrian (Najd fault system) in central Saudi Arabia causedreactivation of the older fault systems and resulted in the uplift of this area. This block-faulted QA structure separated the two

Infracambrian (Hormuz) salt basins and has profoundly influ-enced structure and sedimentation in the region since Palaeo-zoic times (Al-Husseini 2000) (Fig. 2). To date, no detailedinformation about the presence of the Cambro-Ordovician

Fig. 2. After Najd tectonic activities in the Infracambrian, the Qatar Arch high structure separated the Hormuz salt sub-basin in the east fromthe west. During post-Infracambrian time, these horsts and troughs were repeatedly rejuvenated. The illustrations show the thickness of sediments in these sub-basins (A–B cross-sections). Sediment thickness is estimated from regional isopach maps (Permian to Oligo-Miocenedata presented by Bahroudi & Talbot (2003) and Silurian data from Bordenave (2008)) that show the tectonic history and also non-depositionaland/or erosional events in this region. KZ, Kazerun; NZ, Nezamabad; RK, Razak faults.

Reservoir quality of South Pars gas field, Persian Gulf 327



sediments of the QA has been published. These sub-basins were rejuvenated during the Silurian, resulting in the depositionof thin source-rock intervals to the west and the east of theexisting QA (Bordenave 2008). Some workers consider that thethinning of the Permian sediments indicate the existence of asyn-depositional structural high in this region (Edgell 1977;Kashfi 1992).

There was no sedimentation during Triassic to Middle Jurassic times due to end-Triassic tectonic activity and uplift inthe QA (Murris 1980). This non-depositional event is recorded

as an erosional surface on the seismic data. The QA was apositive structure during Late Jurassic times, separating theGutnia platform into two sub-basins (the South Persian Gulf and Central Arabia) (Saint-Marc 1978; Pollastro 2003). Sedi-ment thinning over the crests of the QA structure providesevidence for renewed uplift during the Cretaceous. The archhas also been active periodically throughout the Late Cenozoic,

when sediments currently exposed on the QA were deposited(Alsharhan & Nairn 1997).

The sediment thickness (derived from the regional isopachmaps; Bahroudi & Talbot 2003; Bordenave 2008), describes theevolution of the Persian Gulf Basin between the Infracambrianand Cenozoic (Fig. 2). Arch reactivation has controlled sedi-mentary cover thickness and distribution. Thus, the reduced

thickness of the sedimentary cover over the QA (some 4 km)compared with adjacent areas (e.g. 7–14 km in Zagros foldbelt), provides evidence for its activity and presence as apalaeohigh during a long period of geological time.

Stratigraphic setting

Stratigraphic successions in the subsurface of the QA consist of (Fig. 3):

+ the post-Precambrian to the pre-Permian clastic sediments(including Silurian sediments as source rocks);

+ the Permo-Triassic sequences of thick limestones, dolomitesand anhydrites, (Khuff equivalents) in the Arabian Plate (asreservoir rocks);

+ the post-Triassic section, predominantly marine sequences

of limestones, dolomites, shales and evaporites with localsandy clastic sequences.

Four major tectono-sedimentary units can be observed inthe area of the Zagros and QA; these have been divided into 11megasequences by Alavi (2004) (Fig. 3).

(a ) Post-Precambrian to pre-Permian unit : during the Palaeozoic(Late Neoproterozoic–Carboniferous), the Persian Gulf Basin

was a zone of steady subsidence. Basement rocks in most regions of the Arabian Plate are covered by sandstones of different ages, which overlie the Late Precambrian or Early Cambrian Hormuz Salt (except in the QA) and limestones(Al-Husseini 2000; Sharland et al . 2001).

In the South Pars field, no wells have been drilled deep

enough to penetrate the pre-Permian sediments, or LowerSilurian source rocks. Consequently, there is no evidenceregarding the nature of the Cambro-Ordovician sequences inthe area (equivalent of megasequences (I), (II); Alavi 2004).

Fig. 3. Generalized stratigraphy of the South Pars field showing formation and erosional surfaces detected from the seismic survey. In addition,four rock groups with eleven megasequences (according to Alavi 2004) are shown (not to scale). There is uncertainty about the presence of

Cambro-Ordovician and Silurian sediments in the Qatar Arch. The overall thickness of the stratigraphic column is approximately 4 km. Thestratigraphic position of the studied intervals ( Upper Dalan and Kangan carbonates) is highlighted.




There are different opinions regarding the presence (e.g.Konert et al . 2001) or absence (e.g. Bordenave 2008) of Siluriansource rocks in the QA.

(b ) Permo-Triassic unit : two megasequences, III and IV (including Faraghan, Dalan, Kangan and Dashtak formations),

were deposited in the newly opened ocean (Neotethys). TheDalan and Kangan Fm. are conformably overlain by rusty-brown or variegated Aghar Shales at the base of the Dashtak

Formation, which acts as a regional seal for the QA petroleumsystem (Bordenave 2008).

(c ) Jurassic–Cretaceous unit : during the Jurassic–Cretaceous, vast epicontinental seas developed, which led to the accumula-tion of four marine carbonate megasequences (V, VI, VII and

VIII). These extended over most of the peripheral parts of thePersian Gulf area (Alsharhan & Nairn 1997; Alavi 2004;Farzadi 2006). Erosion and non-deposition in the Triassic to

Jurassic transition was caused by structural uplift combined with a lowstand in sea-level in the Arch (Murris 1980; Ziegler2001). The Post-Turonian erosion, which removed parts of thesedimentary cover in the Arch area and Zagros belt, separatesthe third and fourth rock units (Murris 1980; Alavi 2004).

(d ) Late Cretaceous–Recent rock unit : the uppermost mega-

sequences (IX, X, XI), which are Early Senonian to Recent, were deposited following the onset of the Zagros orogeny,resulting from the progressive closure of Neotethys in theregion (Murris 1980; Sharland et al . 2001). This fourth import-ant tectonic stage in the evolution of the QA and adjacent areais associated with mostly carbonate deposition (Sachun,

Jahrum, Asmari, Gachsarana and Mishan Fms) (Alavi 2004;Konyakhov & Maleki 2006).

DATABASE AND METHODS

In this study, cores, thin sections, isotope data ( 18OPDB

and13C

PDB ), logs, core plugs and petrophysical analyses from ten

wells, drilled in the Upper Dalan–Kangan formations, were

used (Table 1). Thus, our study is based mainly on examina-tions of the subsurface data across the Iranian domain of theSouth Pars field. In these wells, where samples were available,there were log data (gamma ray (GR), density) for reconstruc-tion of uncored intervals. Core and thin-section analysis werecombined to identify facies types and their related diageneticalteration, with special regard to the porosity evolution. A totalof 850 petrographic thin sections stained with Alizarin Red-S

were used for carbonate mineralogy determination. Stableisotope ratios

18OPDB

and 13C

PDBwere determined by

standard methods in 112 whole samples.

GENERAL RESERVOIR CHARACTERISTICS OFTHE SOUTH PARS FIELD

The Upper Dalan–Kangan strata in the South Pars field (andalso in the North field) include four reservoir units – K1, K2,K3 and K4 – with increasing depth (from 2750 m to 3200 m;

Fig. 4). Generally, the average thickness of the reservoir unitsreduces from the South Pars (some 450 m) to the North field(385 m). The reservoir successions are composed mainly, fromthe base upwards, of fine- to medium-crystalline dolomite, witha few intervals of limestone and anhydrite.

K4, the deepest interval, has an average gross thickness of about 165 m with high porosity. Some 55–60% of the K4 unitsare dolomitic carbonate that overlies the Nar anhydrite member(the possible equivalent of Middle Anhydrite in Qatar).

K3 has an average gross thickness of 121 m, comprising more than 70% dolomite. Thick intervals of anhydrite andanhydritic carbonate (up to 50 m), recognized as a permeability barrier in the lower part of K3, separate this unit from K4(Rahimpour-Bonab 2007). Apparently, this barrier interval isequivalent to the dense Upper Anhydrite unit (UA) in theNorth field.

The K2 limestone interval is about 42 m thick and iscurrently the most important productive zone. However, bothporosity and permeability values show rapid vertical variations;for example, the porosity ranges from 0–35% and the per-

meability from zero to 1000 mD over an interval of just 1 m. The base of K2 is defined by the Permo-Triassic boundary andthe first appearance of a thick bed of tight thrombolite facies.Insalaco et al . (2006) reported that there is no major uncon-formity between the K2 and K3 units, but a recent detailedstudy (Rahimpour-Bonab et al . 2009) of this boundary (using sedimentology, geochemistry, petrophysics and biostratigraphy)indicates an important unconformity at this time interval in thisfield.

The K1 interval (about 111 m thick) generally shows higherporosity but lower permeability. Lithologically, this intervalconsists of 70–80% dolomite. Thick anhydrite and anhydriticcarbonates separate these units at the basal part of the K1 andthe top of K2. The contact between the Dashtak (cap rock) and

Kangan formations (K1 unit) is recognized by the high GR log response and the beginning of shale facies (Aghar shalemember of the Dashtak Fm.).

The reservoir properties of these units in ten wells of thefield are illustrated in Figure 4. In these reservoir units, porosity and permeability vary widely from near zero to 36% and 0.001to >3000 mD, respectively. On the whole, based on these data,reservoir quality of the K4 and K2 units is better than the K3and K1 units. Gross reservoir quality is around 9.7% porosity and 26.8 mD permeability (arithmetic mean; 5.46% porosity and 1.44 mD permeability, geometric mean). However, net pay may be significantly less than the gross pay in all reservoir units.

As discussed by Ehrenberg (2006) and Rahimpour-Bonab(2007), the reservoir rocks of this field are heterogeneous at a

variety of scales ( particularly in vertical intervals).

DEPOSITIONAL ENVIRONMENT AND ITSCONTROLS ON RESERVOIR PROPERTIES

Facies analysis

For facies analysis, core examinations and detailed thin sectionstudies were combined. Based on the textures, grains size andtype (such as ooids, peloids, shells and other diagnosticallochems), lithology, sedimentary structures and other features,14 facies were documented in the Upper Dalan–Kanganreservoir in the South Pars field (Figs 5 and 6).

To evaluate their depositional settings, these facies were

compared with modern and ancient analogues that are welldocumented in the literature. Five facies assemblages indica-tive of deposition within supratidal, intertidal, lagoon, shoaland off-shoal environments were identified (Figs 5 and 6).

Table 1. Available data in each well of the South Pars field

Data and methods Wells

Cor e material ( core analy sis ) A, B, C, D, E, F, G, H, I, J

Polarizing microscope (thin section study) A, B, D, E, J Well log data ( GR, ROHB ) A, B, C, D, E, F, G, H, I, J

Petrophysical data (core poroperm data) A, B, C, D, E, F, G, H, I, J

Geochemical data ( 18O and 13C) E, J

Digital point counting (image analysis) A

Well locations are shown in Figure 1.




Datasheets combining all the available information were pre-

pared for each well (e.g. Fig. 7).Facies F1 and F2, dense anhydrite and anhydritic dolomitesediments ( c . 2.7–3 g cm3 ), in which anhydrite occurs eitheras a nodular fabric (chicken wire) or as massive and layered

anhydrite. Warren & Kendall (1985) and Warren (2006) pro-

posed evaporative sabkhas of the Trucial Coast as a modernanalogue for these facies.Facies F3 and F4, dolomite lithology with mudstone texture,

are massive and homogeneous. Facies F3 can be distinguished

Fig. 4. Comparison of thickness, lithology, porosity, water saturation and other reservoir characteristics in the studied reservoir units in ten wellsof the South Pars field. As illustrated by these parameters and scatter plots of the porosity vs. permeability (right), the reservoir qualities of K2and K4 units are higher than those of the K3 and K1 units.




from F4 by its anhydrite (rhombs) and gypsum crystals. Thesefacies are associated with F1 and F2. Modern analogues forthese facies are peritidal environments (particularly from inter-tidal ponds) (Tucker & Wright 1990; Flügel 2004).

Facies F5 is a thrombolite/stromatolite boundstone charac-terized by a laminated/layered fabric. This thrombolite is welldeveloped just after the Permo-Triassic boundary as a post-massextinction facies (7–10 m thick in reservoir rocks). Microbial

Fig. 5. Field-scale facies model reconstructed for the Upper Dalan–Kangan carbonates system in the South Pars field. Fourteen facies types arerecognized in this environment that juxtaposed along the peritidal to off-shoal settings. Within the shallower part of this carbonate ramp, fivemain facies belts can be distinguished. The whole depositional realm was clearly above the fair weather wave base. Also shown is the schematicdepositional facies model, based on the cores and thin sections, together with the idealized sequences for this environment.




Fig. 6. Diagrammatic cross-section through the carbonate ramp illustrating the distribution of the 14 main facies types, based on their small-scalecycles. Photomicrographs of six important facies types, characteristic of their depositional environment, are also shown.




laminates with abundant fenestrate and laminated structures aretypical features of the intertidal environments described from

both modern (Persian Gulf, Florida and the Bahamas) andancient tidal flat systems (e.g. Shinn 1983; Flügel 2004).Fenestral dolomudstones (Facies F6) have a fenestral fabric,

muddy (mudstone and wackstone) texture with ostracod shells

and dolomite lithology. This facies type is interpreted as anintertidal deposit. The ostracod wackestone, with characteristic

bird’s-eye porosity, is also indicative of an intertidal environ-ment close to supratidal flats (e.g. Shinn 1983; Wright 1984).Facies F7 consists of peloid/intraclast grain-dominated

textures, with grain grading and commonly massive structure.

Fig. 7. Datasheet example. Data from each studied borehole core (here: well A in the South Pars field) are combined in a datasheet forinterpretation. These datasheets contain gamma-ray, density and sedimentological logs and poroperm values. The graphic well logs indicate that the Upper Dalan–Kangan reservoir intervals are mud-dominated (low-energy) and dolomitized. The reservoir rocks show changes in thedepositional realm from supratidal to an open-marine environment. Based on the integration of sedimentological criteria and well-log signatures,the Upper Dalan–Kangan carbonates in the South Pars field are subdivided (from the base to the top) into four depositional sequences. Therelationship between these sequences and reservoir characteristics (also reservoir intervals) is shown. Diagenetic effects within the reservoir rocksprevent generalizations from being made about reservoir quality.




In this facies, which is associated with the peritidal facies(particularly F5), shell fragments are absent (or rare). Gradedpeloidal grainstones are described as washover sediments fromstorm events (Wanless et al . 1988). This facies association isindicative of an intertidal bar and channel depositional environ-ment (Tucker & Wright 1990; Flügel 2004).

Peloids are common in facies F8 and F9. Boring andbioturbation, and some restricted marine monospecific fauna(such as gastropod and miliolida) are commonly observed

within a lime mud matrix. In modern peritidal carbonateenvironments, subtidal and lower intertidal zones show inten-sive bioturbation (Shinn 1983; Flügel 2004) and these featuresare typical of lagoon (restricted platform) development in theshallow-marine carbonate sequences (e.g. Scholle et al . 1983;

Tucker & Wright 1990).Facies 10 is a poorly sorted, bioclastic packstone (limestone

or dolomite) with diverse fauna (mixed restricted and open-marine fauna). It is highly bioturbated (massive structure) andcontains biomoulds. Green algae and oncoids are commonallochems in this facies. According to Wilson (1975), Scholle

et al . (1983) and Flügel (2004), these features are typical of openshallow lagoonal and back-bank settings.

Oolite-rich facies (F11, F12 and, in some cases, F13) in thereservoir intervals show massive structures (mostly F11 andalso F12), cross-bedding or grain-grading and orientation.

These are common features of an oolitic shoal complex. Similaroolitic wackestones to grainstones, with comparable texture andspatial distribution, have been described from several modernenvironments, such as the present-day Persian Gulf.

Facies F14 is a dark mudstone with well-preserved lamina-tions and open-marine fauna. It is closely associated withthe oolitic shoal complex facies. Wave and current-inducedstructures are absent, suggesting a subtidal environment below

wave base (Keller 1997). This facies is devoid of indigenous

benthonic fauna or burrows, which may reflect anoxic con-ditions during deposition (Marquis & Laury 1989). According to many authors, this facies is deposited in the offshoal setting below fair-weather wave base (FWWB).

These facies are repeated vertically through the reservoirunits. Individual facies may range from decimetres to severalmetres. By environmentally grouping different facies, two maingroups can be recognized. Type A comprises facies F1–F8(supratidal, intertidal and restricted lagoon facies); these arecommonly overprinted by dolomitization and anhydriticcementation. More than 70% of the Upper Dalan–Kangansuccession in the field consists of anhydrite- and mud-dominated sediments (approximately 70% in K4, 85% in K3,20% in K2 and 88% in K1). This facies group was deposited

landward of the studied palaeo-platform under low-energy conditions.

Type B comprises facies F9–F14, which were deposited inopen lagoon, shoal and offshoal settings. This facies group isassociated with high-energy conditions situated on the seawardflank of a platform. Some 30% of the reservoir intervals arecomposed of these sediments (approximately 30% in K4, lessthan 10% in K3, 80% in K2 and 12% in K1).

Regional and field-scale depositional model

The lateral distribution of the documented facies belts, along the carbonate ramp system, were reconstructed (Figs 5 and 6).

They extend from the peritidal setting to the shallow subtidal

zone through a high-energy shoal facies. The reservoir rocksconsistently show gradational changes upwards from shallow-to deep-water ramp facies, with thick sections of shallow-watersediments. However, temporal distributions of these facies

associations reflect an ideal shallowing-upward sequence. Faciesanalysis shows gradational transitional boundaries within thefacies associations, suggesting that they are genetically relatedand demonstrating a very low depositional gradient and mor-phology. Similar interpretations have been reported for theKhuff Formation (equivalent of Upper Dalan–Kangan forma-tions) (e.g. Al-Aswad 1997; Alsharhan 2006).

We have reconstructed the depositional system of the UpperDalan–Kangan in the South Pars field on the shallow parts of a homoclinal carbonate ramp (Figs 5 and 6). This interpretationis based on the facies characteristics, their lateral and verticalrelationships, the presence of a thick succession of shallow deposits (relatively high proportion of peritidal and lagoon

versus open-marine facies), the absence of reef and mass flow deposits (re-sedimented deposits) associated with a shelf break (margin) and the low diversity of facies types (Ahr 1973; Read,1985; Burchette & Wright 1992; Avrell et al . 1998). At theregional scale, facies types and assemblages of the UpperDalan–Kangan successions represent a shallow-marine carbon-ate system of epiric or ramp-like environment (Al-Aswad 1997;

Insalaco et al . 2006). This depositional environment is closely comparable to the present-day Persian Gulf carbonate system,

which is well known and well documented (Alsharhan &Kendall 2003). Seemingly, the strata in this study weredeposited over the inner part of such a carbonate system.

Regionally, juxtaposition of different depositional faciesindicates a change from the offshore to the onshore setting (Zagros outcrops), where more supratidal-dominated condi-tions replaced the open-marine environment. Small fluctuationsin the sea-level in this environment resulted in considerableshifts in the location of the ancient shoreline (Alsharhan &Nairn 1997; Insalaco et al . 2006). Based on the integration of sedimentological criteria and well-log signatures, the UpperDalan–Kangan carbonates in the South Pars field have been

subdivided (from the base to top) into four depositionalsequences (Fig. 7). The characteristic sequence of this intervalis reconstructed in Figure 5.

Facies, rock types and reservoir quality

The importance of palaeoenvironmental controls on theporoperm values of the studied units can be deduced by examining the relationships between depositional facies andreservoir properties. In general, scatter plots for the coreporoperm values versus depositional facies suggest that grain-dominated subtidal facies (Type B facies group) have the best reservoir quality (Fig. 8 and Table 2). In general, the range of poroperm values corresponds to the environmental energy

gradient which increased from land to the high-energy shoalsetting and decreased in the off-shoal facies. Thus, there is adirect relationship between the distribution of the reser-

voir properties and the facies heterogeneities in the studiedreservoir.

The mass extinction at the Permian–Triassic boundary canbe recognized in the reservoir units. Following the massextinction, primitive groups of microbial communities emergedfrom the stressed palaeoenvironment. As documented on thebroad Tethyan carbonate platform, they re-colonized normalmarine settings during a very rapid and large-scale platformflooding event (earliest Triassic) (Baud et al . 2005; Insalacoet al . 2006). The important shift from skeletal to non-skeletalcarbonate factory, due to the Permo-Triassic extinction, is

recorded in the reservoir rocks of this field (Facies F5). Thisend-Permian to basal-Triassic thrombolitic zone (7–10 m thick)has influenced the reservoir quality and other physicochemicalproperties of the underlying reservoir units (Fig. 9). In addition,




this zone is influenced by the extensive meteoric diageneticoverprints. Decrease in the log values (GR and ROHB),poroperm values and isotopic ratios ( 18O

PDBand

13CPDB

)are the main features of this interval, which is laterally traceablein all wells (Fig. 9). This thin laterally extensive horizon acted asthe main barrier to vertical fluid flow.

Petrophysical examination of different facies types showsstrong variations in the porosity and permeability (Fig. 8).

These variations in the pore spaces were caused by depositionalconditions and diagenetic overprints. In order to define petro-physical classes, it was necessary to classify pore spaces. The

widely used standard description of carbonate rocks based onthe Dunham (1962) classification is insufficient to provide a

clear understanding about fluid flow and reservoir behaviour(Cantrell & Hagerty 2003; Kostic & Aigner 2004; Ruf & Aigner2004). In this study, the Ruf & Aigner (2004) approach is usedas the rock-typing system for the reservoir rocks. These rock

types exhibit meaningful relationships with the poroperm values (Fig. 10).

The standard textural (Dunham 1962) and pore space(Lucia 1995) classifications define four rock type groups (RTG)and 16 rock type classes for these rocks (Fig. 10, left). In thisstudy, reservoir rocks are subdivided by their texture (grain-stones, packstones, wackestones and mudstones; abbreviated asG, P, W and M, respectively) and dominant pore spaces (tight,separate vug, touching vug and interparticle; abbreviated as T,SV, TV and IP indices, respectively). Therefore, four RTGsinclude: rock texture with tight pore spaces or T

T(M

T, W

T, P

T,

G T

), rock texture with separate vug pore spaces or TSV

(MSV

, W

SV , P

SV , G

SV ), rock texture with touching vug pore spaces or

T TV (M TV , W TV , P TV , G TV ) and rock texture with interparticlepore spaces or TIP

(MIP

, W IP

, PIP

, GIP

) (Fig. 10). The main results from the correlations of rock type groups

and their poroperm values can be summarized as follows.

Fig. 8. Porosity–permeability cross-plot based on the facies types. As shown, there are strong variations between different types as well as withinsingle types. Comparison of the reservoir properties in various facies indicates that subtidal grain-dominated facies (especially F8, F9, F10, F12and F13) have better poroperm values than the landward mud-dominated and anhydritic facies.

Table 2. Statistical parameters of each facies according to the means of porosity and permeability

Facies type Arithmetic mean Geometric mean Coefficient of determination (r2 )

Porosity ( %) Permeability ( mD ) Porosity ( %) Permeability ( mD )

F1 3.14 4.75 0.78 0.17 0.21

F2 7.18 29.51 3.96 1.81 0.27

F3 4.79 2.47 2.17 0.14 0.27F4 7.75 55.55 3.48 0.77 0.28

F5 7.45 193.44 3.51 3.48 0.32

F6 10.23 28.88 5.58 1.80 0.58

F7 10.10 23.45 4.62 4.21 0.23

F8 10.16 27.25 6.05 1.94 0.57

F9 13.00 20.89 8.49 2.31 0.55

F10 18.15 57.98 12.25 6.61 0.26

F11 15.88 81.61 14.34 8.39 0.36

F12 21.98 50.12 20.42 5.32 0.03

F13 17.50 3.79 16.34 3.52 0.24

F14 19.24 6.22 19.16 5.72 0.11

Note : In general, poroperm means increase from supratidal facies to the shoal facies (F1–F12) and decrease in the off-shoal facies. These variations in the reservoirquality correspond to the depositional energy conditions.




1. By grouping the rock type classes based on the dominant porespaces, discrete fields can be distinguished (Fig. 10). With thisapproach, the reservoir qualities of the Upper Dalan–Kanganreservoir decrease in the following order: T

IP, T

TV , T

SV and

T T

(Table 3). In addition, the relationship between poroperm values and rock type groups are more obvious (than the facies

types) because depositional facies designation ignores theeffects of diagenetic overprinting on reservoir properties(Cantrell & Hagerty 2003; Kostic & Aigner 2004).

2. There is a broad variation of rock type groups with regard tothe poroperm values (Fig. 10), indicating that the reservoirquality is not controlled solely by the dominant pore space

Fig. 9. The basal Triassic thrombolitic zone (Facies F5) in the reservoir units of the South Pars field and its effects on the well-log values,isotopic signatures and petrophysical properties. Appearance of thrombolites after the Permo-Triassic boundary has an important effect on the

vertical heterogeneity of reservoir rocks at the field scale (with 7–10 m thick at the base of K2).

Fig. 10. New rock-typing approachused in this study. According toDunham’s (1962) textural classificationand Lucia’s (1995) pore spaceclassification, 16 rock type classes andfour rock type groups can be defined(left). Relationships between poroperm

values with the rock type groups aremore pronounced than the facies types.Correlations of these rock type groups

and poroperm values indicate that reservoir quality decreases in thefollowing order: T

IP, T

TV , T

SV and T

T

(right) (see Table 4).




type. Additional coding of the porosity and permeability according to their textural types and parameters (grain size,sorting etc.), in combination with these rock types, may leadto better-defined fields.

3. Grouping and definition of the rock types based on theDunham (1962) depositional textures, without considering the pore system, may not reveal well-defined fields (Fig. 11).

The vertical distributions of the facies in the studied units

show cyclical patterns. As discussed, facies types haveexerted an important control over the reservoir quality.

Thus, it is reasonable to expect that the cyclical patterns of facies distribution have influenced the poroperm properties.Changes in the vertical successions of facies with downdipposition, along with the log data, imply that these strata arecomposed of several stacked packages, representing deposi-tional cycles.

On the basis of the facies systematic arrangement, facies-related diagenetic patterns, as well as log data (GR and ROHB),four depositional sequences (third order) are identified, whichshow distinctive petrophysical properties (Fig. 7). Thesesequences are bounded by chicken wire and nodular anhydrite

and dolomudstones (landward facies) at the top and at the base.Generally, the latter units that separate fluid flow units are tight. A general basinward progradation of the platform faciesoccurred during deposition of the Upper Dalan–Kangan car-

bonates, with tidal-flat and lagoonal facies succeeding shoal andsubtidal facies.

The diagenetic effects on the reservoir rocks prevent usmaking precise generalizations about relationships between thereservoir quality and sequences. Our results demonstrate that depositional variables exerted primary controls over the reser-

voir quality and productivity of the Upper Dalan–Kangan unitsin the South Pars field.

DIAGENESIS AND RESERVOIR QUALITY

Diagenetic history and porosity evolution

There are a few published detailed diagenetic studies on thereservoir rocks of the Qatar Arch large gas fields (e.g.Ehrenberg 2006; Rahimpour-Bonab et al . 2009). We propose adiagenetic reservoir model for the complex diagenetic history (Fig. 12). The model has four stages and records the successionof the diagenetic environments and processes. Thin-sectionphotomicrographs of some diagenetic features are shown inFigure 13. Two diagenetic regimes were identified. Early diagenesis occurred before the onset of pressure-solution,

whereas late diagenesis occurred during and after pressure-solution. Our studies have shown that the diagenesis that improved reservoir characteristics occurred in the meteoricrealm, i.e. during shallow burial. Most of the reservoir porosity

Table 3. Statistical parameters of di ff erent rock type groups according to the porosity and permeability values

Rock type groups Arithmetic mean Geometric mean Coefficient of determination (r2 )


TIP 15.94 202.26 9.74 46.25 0.48 T TV

15.06 67.33 10.79 18.50 0.20

TSV

15.76 12.63 11.88 3.17 0.02

T T

3.21 2.03 1.89 0.08 0.46

Note : The reservoir quality of the reservoir rocks decreases in the following order: TIP

, T TV

, TSV

and T T

.

Table 4. Statistical parameters for di ff erent lithologies according to the porosity and permeability values (mean values)

Lithology Arithmetic mean Geometric mean Coefficient of determination (r2 )


Dolomite 7.67 39.97 5.36 1.06 0.12

Calcite 13.56 17.57 8.98 0.92 0.04

Anhydrite 2.58 2.98 2.00 0.10 0.12

Fig. 11. Comparison of different Dunham depositional textures of TSV

(left) and T TV

(right) with regard to theporoperm values. No well-defined fieldscould be distinguished between varioustextural types of each group.




is secondary in origin and was formed during diagenesis (Fig.13). Detailed petrographic study has clarified the role of selective diagenesis in the reservoir history. Diagenetic featuresare heterogeneous in the limestone and dolomite-rich sedi-ments; however, they have strongly influenced porosity andpermeability in both lithologies.

The main diagenetic processes affecting the Upper Dalan– Kangan reservoir units include: (1 ) micritization and marinecementation (Fig. 13C, g); (2) formation of anhydrite nodules(Fig. 13H, o, n); (3) early dolomitization and dolomite neo-morphism (Fig. 13A, a; 13B, b; 13C, g); (4) dissolution and/orneomorphism of aragonite (generation of secondary porosity)(Fig. 13C); (5 ) anhydrite and calcite cementation ( Fig. 13C, D);(6) mechanical and chemical compaction (Fig. 13D, F, G, H);and (7) minor fracturing. Diagenetic processes of local impor-tance are saddle dolomite precipitation and anhydrite replace-ment. Many of these effects overlap.

Evidence for aragonite dissolution and low Mg-calcitematrix preservation imply evolution of the secondary porosity in these carbonates (Fig. 13C). Although dolomitization, dolo-mite neomorphism (Fig. 13G) and fracturing have had a minorinfluence on porosity generation, in some cases, they have hadan important effect on the permeability values (particularly inK4).

Diagenesis during burial tended to reduce reservoir quality through physical compaction, anhydrite precipitation and car-bonate cementation (There was some porosity generation as aresult of dolomite neomorphism, stylolitization and fracturing.)Four stages of diagenetic alteration have affected reservoirquality (Fig. 12).

+ Stage 1: Syn-depositional and marine diagenesis . This stage displaysnormal sedimentation conditions in the shallow part of acarbonate ramp system. Formation of anhydrite nodules andearly matrix dolomite in the peritidal setting, micritization,

bioturbation and marine calcite cementation in the subtidalfacies mostly occurred during this stage (Fig. 13C, H).Primary porosity was generated and subsequently modifiedby these processes (Fig. 12, Stage 1).

+ Stage 2: Hypersaline diagenesis . This stage is characterized by theparagenesis of early dolomitization in sabkha and hyper-saline environments with related pore-filling anhydritecement and widespread anhydrite nodularization processes(Fig. 13A, B, E, H ). These processes are associated with theperitidal and restricted lagoon facies and affected productsof the earlier stages of diagenesis in an arid climate. Most of the earlier created pore spaces were occluded by anhydritecementation (Fig. 12, Stage 2).

+ Stage 3: Meteoric diagenesis . Through sea-level fall, shallow facies belts of this platform were subaerially exposed to thepresumably humid climate. The main features of this stageare leaching and neomorphism of unstable grains, as well aslater meteoric calcite cementation (Fig. 13C). Seemingly,more than 60% of the reservoir porosity was createdthrough leaching at this stage (Fig. 12, Stage 3).

+ Stage 4: Burial diagenesis . Dolomite neomorphism, compac-tion, cementation (anhydrite and calcite), fracturing andsaddle dolomite precipitation affected the reservoir unitsduring this stage and reduced the poroperm values (Fig.13D, F, G, H). Burial diagenesis continued to depths of 2.5–3.2 km (Fig. 12, Stage 4).

Diagenetic controls on the reservoir quality

Lithology, dolomitization and poroperm values

Calcite, dolomite and anhydrite are three common mineralsdistinguished by thin section examinations. The field-scalecorrelations between core and thin section examinations indi-cate that the reservoir rocks are composed of dolomite,limestone and anhydrite of some 60%, 30% and 10%, respect-ively. Approximately 20% of K1, 90% of K2, 30% of K3, and50% of K4 are of limestone lithology.

The comparison of the poroperm values for these litholo-gies reveal a clear relationship between lithology and thereservoir quality. Generally, dolomitic intervals of the reservoirrocks are more permeable than the limestone and anhydrite

Fig. 12. The diagenetic model for thereservoir units in the South Pars fieldhas four stages: (1) syn-depositionaland marine; (2) hypersaline; (3)meteoric; and (4) burial diagenesis.




Fig. 13. Diagenetic aspects of the Upper Dalan–Kangan in thin section photomicrographs in the South Pars field. ( A ) Fabric-selectivedolomitization pre-dates compaction processes; well-rounded grains (a: ooids) are preserved. ( B ) Mimic dolomitization in the reservoir rock (b:dolomitized ooid grains; c: non-dolomitized marine isopachous cements; d: pore space generated during dolomitization of grains (?); e: intergrainporosity). ( C ) Calcite-cemented ooid-grainstone with micritized grains (f) and marine calcite cements (g). ( D ) Stylolites (h: stylolitic pore

spaces). ( E ) Peloid packstone/wackstone with extensive anhydrite plugging ( g: poikilotopic anhydrite). ( F ) Features of burial diageneticprocesses, including concave–convex boundary between compacted grains (l ), microstylolite (j ) parallel with the microfractures (k ). ( G ) Ghost of stylolite features (m) is overprinted during dolomite neomorphism. ( H ) Anhydrite crystals (n) and micro-nodules (o) cross-cut with thestylolites.




successions (Fig. 14, Table 4). Although, limestone intervalsshow higher porosity values, they are commonly associated

with lower permeability (for example in the middle part of K4). Anhydritic units are mostly associated with non-pay (tight)

intervals but, in some cases, the reservoir quality of these unitsis increased due to fracturing or dissolution. These intervalsmainly occur in the lower part of K3, upper part of K2 andlower part of K1.

Therefore, a key question relates to the effects of dolomiti-zation on the reservoir quality. In the carbonate reservoirs, thestable carbon and oxygen isotopic compositions of the dolo-mites may provide insight regarding their genesis and porosity development (i.e. Saller & Henderson 1998). Sedimentological,petrographic and geochemical data indicate that sabkha andreflux models are the two main mechanisms for dolomitizationin the dolostones of the Upper Dalan–Kangan formations inthis field. Similar dolomitization mechanisms were reported forthe Khuff reservoir (Ehrenberg et al . 2007). In general, dolo-

mitization processes have preserved the initial rock fabric anddolomite crystals are fine to medium in size (mimic dolomiti-zation). Based on the petrographic relationships and isotopiccompositions, the coarse crystalline dolomite in the K4 interval(several metres) is ascribed to neomorphism (Fig. 13G). Themicrocrystalline dolomite (commonly F6 and/or W

IP, M

IProck

types) with high intercrystalline porosity is one of the best reservoir facies in this field.

In the Kangan reservoir (particularly K2), correlation of thepetrographic and geochemical values with the poroperm valueshas indicated that dolomites with heavier

18O values havebetter reservoir quality in comparison with the limestones.

There is a positive correlation between low-poroperm andlow-isotopic values (in both

13C and 18O values) (Fig. 15).

Poroperm values of dolomites are controlled mostly by theprecursor sedimentary fabrics and the original porosity. Although dolomitization does not create significant pore spacesin the reservoir rock it has positive effects on pore connections.

According to this study, reservoir quality has been slightly improved by dolomitization.

Dissolution

Petrographic observations have shown that dissolution is themost important factor in porosity creation in the South Parsfield (Fig. 13C). This process has been recognized as a key factor in generating reservoir quality in all Khuff reservoirs(Ehrenberg et al . 2007). The digital point counting method wasused to differentiate dominant pore types in the studiedreservoir rocks (by the Jmicrovision v1.2 Image AnalysisSoftware). More than 600 thin section microphotographs from68 samples in well A were analysed. The results indicated that there are seven dominant pore types in these reservoir units.

The relative abundance of these pore types is presented inFigure 16. The most common pore types (mouldic and solutionenlarged, up to 60%) in the reservoir rocks were produced by dissolution of the unstable components.

Earlier studies reported that mouldic pores increased theporosity but had little effect on the permeability (e.g. Lucia1999); however, the association of these pore types withinterparticle (shoal complex facies) and touching vugs (e.g.fractures) has increased the poroperm values. This study showsthat the best reservoirs are found in grainstone/packstonelithologies with a high mouldic and interparticle porosity and indolomitic grainstone/packstone sediments (in the rock typesG

IP, P

IP, G

TV and P

TV ). These reservoir facies formed thick

intervals in the lower and middle parts of K2 and middle part of K4 units. Near-surface leaching processes are associatedmostly with the limestone intervals (open-marine grainy facies),because early dolomitized sediments were more stable inmeteoric conditions than limestone. The fabric-selective disso-

lution during meteoric diagenesis created solution pores.

Cementation

Cementation, particularly by anhydrite, is the dominant mech-anism of porosity destruction in carbonate reservoirs (e.g.Southwood & Hill 1995). The two main types of cements inthe studied intervals are anhydrite and calcite (Fig. 13C, E). Inaddition, there is minor fracture-filling dolomite cementation(saddle dolomite) during the late stages of diagenesis. Thin-section examination indicates that there is a greater volume of early cements than the late cements. Anhydrite cements aregenerally associated with the dolomitic intervals (supratidal,intertidal and lagoon facies), whereas calcite cements are

associated with the limestone intervals that include open-marine facies (high-energy facies such as F10, F12 and F13).

Visual estimations indicate that the most common type of cement in the reservoir intervals is anhydrite. The main porosity occluding cements (calcite and anhydrite) were precipitatedearly in the diagenetic history. Commonly, cementation hasnegative effects on poroperm values (Fig. 17). In many cases,pore spaces are completely occluded by cement (in the P

Tand

G T

rock types, for example tightly anhydrite cemented lagoonalfacies in the middle part of K3) (Fig. 13C, E). The types andeffects of cementation on reservoir characteristics were evalu-ated from visual estimations of cement (according to Cantrell &Hagerty 2003). Facies with more than 10% cement (without considering cement mineralogy) have lower permeability than

other facies (Fig. 17a). Presumably, there is a clear relationshipbetween cement type and reservoir quality. In most cases,calcite-cemented facies have better poroperm values than theanhydrite-cemented ones (Fig. 17b).

Fig. 14. Relationship between lithology and poroperm values.Generally, these cross-plots indicate that although dolomitic intervalsare slightly more permeable than the limestone and anhydrite, they show similar porosity values.




Compaction

Thin-section and core examinations all indicate that the reservoir rocks in this field have been affected by compaction fromdeposition through to deep burial. Most depositional fabricsshow little evidence for compaction prior to dolomitization,suggesting that this process pre-dates compaction (Fig. 13A,B).

As a result of increasing compaction ( extensive chemicalcompaction), solution seams and stylolites are developed. Inmost cases, stylolites pass through dolomite and anhydritecrystals, but the latter crystals were not observed to grow along the stylolites (Fig. 13H). Most of the stylolites are parallel to thebedding surface and developed between two facies. The spatialdistribution of the stylolites is determined by the depositionaldistribution of clay minerals in the reservoir rocks ( Ehrenberg 2006). Therefore, the palaeoenvironmental energy conditions

have controlled localization of these compaction features. Inmost cases, stylolites occur in the mud-dominated faciesparticularly in the middle and upper part of K3 and also K1units. In the K4 units, stylolites generally occur in the lowerpart and also in the lower and upper parts of the K2 unit. Thepressure-solution and stylolitization processes supplied thenecessary materials for late burial cementation that are associ-ated with the post-compaction cements. This process occludespore spaces which are generated and preserved during earlierstages of diagenesis (Ehrenberg 2006).

To analyse the compaction effects on the reservoir proper-ties, the number of stylolites (per metre) were counted throughcore examinations. Results of this study indicate that theporoperm values and the reservoir quality decrease with the

increase in the stylolite abundance (Fig. 18). In summary,compaction (stylolitization) has a negative effect on bothporosity and permeability. Results of this study are supportedby Ehrenberg’s (2006) findings in the South Pars field.

Fig. 15. Plot of the poroperm andstable isotope values for the Kangandolomites and limestones in the SouthPars field. Two typicalphotomicrographs of K2 dolomite andlimestone are also shown. There is apositive correlation between

low-poroperm and low-isotope valuesin dolomite and limestone lithologies(in both

13C and 18O values).

Fig. 16. Seven basic pore types are distinguished in the reservoirstrata in the South Pars field. Relative proportions of each pore typesare displayed.




Fracturing

Macro- and microfractures occur in the studied reservoir rocks. Their features can be identified in all scales from core samplesto borehole electrical images. Fracture pores account for 13%of the reservoir rock porosity. In many cases, these fractures arefilled by anhydrite, calcite and saddle dolomite cements (min-eralized or closed fractures). Elsewhere, open-fracture systemscan connect isolated porosity. However, the precise role of thefracturing and its affect on reservoir quality in this field is not

well understood. Akbar et al . (2000) reported the presence of natural and

drilling-induced fractures in these reservoir rocks based on FMIimages analysis (Fig. 19). Fractures induced by drilling domi-nate in most intervals. They are present in K1, K2 and K3reservoir units and, to a lesser extent, in K4 unit. As a whole,K2 and K3 units contain induced fractures, whereas the naturalopen fractures are mainly present in a few horizons in K1 andK4. The latter features are very well developed in the brittledolostones. In some cases, fracturing of dolostones has led tohigh permeability values with minor influence on the porosity (Fig. 19).

DISCUSSION AND CONCLUSION

This study in the South Pars field indicates that the poroperm

heterogeneity in the reservoir rocks is controlled by severalfactors. Facies analysis has identified a depositional setting located along the inner part of a homoclinal carbonate rampthat extended from peritidal to shallow subtidal zones, passing

over a high-energy shoal and off-shoal facies. Generally, corre-lation between facies types and poroperm values shows anincrease in the reservoir quality from shoreface to seawards.

The rock type groups and poroperm values show clear relation-ships with the integration of texture and pore types. They indicate that the reservoir quality in this Permo-Triassic succes-sion is controlled mainly by diagenesis.

Four stages of diagenesis were documented in which depo-sitional facies were selectively overprinted by shallow and burialdiagenetic processes. However, in terms of origin, all studiesshow that the reservoir quality resulted primarily from dissolu-tion in the shallow diagenetic settings. In addition to facies anddepositional controls, five main diagenetic factors affected thereservoir quality at field-scale: lithology, dissolution, cementa-tion, compaction and fracturing.

In conclusion, the original poroperm heterogeneities in theUpper Dalan–Kangan reservoir are inherited from their palaeo-platform depositional setting but were modified subsequently during diagenetic processes. Therefore, for precise characteri-zation of the reservoir properties in such a heterogeneouscarbonate reservoir, integration of sedimentary and diageneticfeatures is essential.

The vice-president of Research and Technology of the University of Tehran provided financial support for this research (grant no.6105023/1/03), for which the authors are grateful. The authors alsoextend thanks to the POGC (Pars Oil and Gas Company of Iran) for

sponsoring, data preparation and permission to publish this paper. We also thank two anonymous reviews for their invaluable com-ments and suggestions that highly improved the first draft of thispaper.

Fig. 17. Porosity–permeability cross-plot illustrating the importance of cement quantity and type in controlling the poroperm values of the reservoirrocks. ( a ) With an increase in thecement abundance, the poroperm

values decrease gradually. ( b ) Thecalcite-cemented facies are associated

with better poroperm intervals incomparison with theanhydrite-cemented facies.

Fig. 18. Relationships betweenporoperm values and stylolitefrequencies in the reservoir rocks.

Three groups are classified based onthe stylolite frequencies (per metre).

The core sample of each group is alsoshown. As seen, poroperm valuesdecrease with an increase in the stylolitepercentage.




Fig. 19. Interpretation of FMI log together with the summary plots of all planar features in one well of the South Pars field. Both natural anddrilling-induced fractures occur in the reservoir rocks, but the latter is more common.




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Received 17 July 2008; revised typescript accepted 17 February 2009.


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