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Middle East Models of Jurassic/Cretaceous Carbonate Systems

SEPM Special Publication No. 69, Copyright ©2000 SEPM (Society for Sedimentary Geology), ISBN 1-56576-075-1, p.287–297.

Abstract

The upper Kharaib reservoir of the Lower Cretaceous Thamama Group is one of the major oil-producing horizons offshore Abu Dhabi in the United Arab Emirates, and is traced over the area as a well-defined rock unit. This reservoir is composed of three lithofacies, rudistid-peloidal grainstone/packstone, algal-peloidal grainstone/packstone, and bioclastic wackestone/mudstone. Sediments were deposited on a broad carbonate shelf and show an upward-shallowing succession. Reservoir quality is determined by both original depositional fabric and subsequent diagenetic processes. In general, permeability is variable and porosity is constant throughout the sequence, except for stylolitized intervals.

In the “A” field, six high-permeability facies are identified in the grain-supported interval. These facies are characterized by unique pore-throat size distributions resulting from depositional textures and diagenetic modification. Grain sorting and preferential dissolution, as well as preservation of primary pores, are significant factors in controlling pore geometry. Dolomitization is also locally important. The highest permeability is present in well-sorted, coarse-sized grainstone at the basal part of upward-fining bed sets where well connected intergranular pores are preserved.

Thus, identification of high-permeability facies is crucial if one is to understand the performance of the reservoir under water flood. On the basis of the vertical and lateral distribution of high-permeability facies and pore-throat size distribution, the reservoir was divided into twenty-two sublayers as a basis for reservoir simulation study.

Introduction

The “A” field is located offshore approximately 80 kilometers northwest of Abu Dhabi (Fig. 1). A structural contour on top of the upper Kharaib reservoir, defined as the Thamama II reservoir, shows a broad and gentle asymmetric anticlinal domai feature with dips of a few degrees. The relief in the western area of the field is almost flat, but slightly steeper dips (approximately 3–5°) are recognized on the north and northeast flanks. No major faults have been reported.

Fig. 1.

—Location map of “A” Field, offshore U.A.E.

Fig. 1.

—Location map of “A” Field, offshore U.A.E.

The Thamama II reservoir in this field is a heterogeneous reservoir with permeability as high as a few thousand millidarcies (Nishi and Shibasaki, 1996). Premature water breakthrough in the reservoir has been observed from some wells under the five-spot water injection pattern. Resistivity anomalies in open-hole logs and time-lapse pulsed neutron logs of some wells revealed that a preferential water movement has occurred along relatively thin layers. This evidence suggested the existence of thin, high-permeability streaks acting as conduits of injected water to producing wells.

This paper identifies and classifies high-permeability facies with data from pore-throat size distribution curves, lithological controls, diagenetic influences, and mercury-injection capillary pressure data analysis. This lithological and petrophysical information is integrated to develop a new fine-scale layering scheme for the reservoir.

Geological Setting

The Thamama II reservoir belongs to the upper part of the Kharaib Formation of the Thamama Group (Fig. 2) (Alsharhan, 1990). The Thamama Group of the Lower Cretaceous offshore Abu Dhabi is divided into four formations, the Habshan, Lekhwair, Kharaib, and Shuaiba formations, in ascending order. Sedimentation of these formations is mainly categorized into three depositional phases. The Habshan Formation is marked by a widespread marine transgression and is composed of sediments deposited under various environments from supratidal to shelf, in largely restricted conditions (Hassan et al., 1975; Alsharahan and Nairn, 1986). It is followed by cyclic sedimentation of the Lekhwair and Kharaib Formations resulting from eustatic sea-level changes in shelf environments of a carbonate ramp (Murris, 1980). Reservoir facies consist of regressive sediments having upward-coarsening sequences and are readily traced over the area. The Lekhwair Formation represents normal marine shelf sediments and is developed as a number of cyclic sequences. In general, the trasgressive phase is dominant in the cycles. The Kharaib Formation was deposited in a vast, shallow, epicontinental shelf commencing with a regressive phase of cycles and characterized by predominantly regressive sediments. The Shuaiba Formation was deposited in various environments, influenced by paleogeogra-phy and sea-level changes, represented by deep-water shelf sediments and shallow-water rudist carbonates in some localized areas.

Fig. 2.

—Generalized lithofacies and well-log signatures of the Thamama II reservoir.

Fig. 2.

—Generalized lithofacies and well-log signatures of the Thamama II reservoir.

The Thamama II reservoir is characterized by an upward-shallowing system composed of three major lithofacies deposited on a shallow carbonate ramp during a major regression. The lower part of this reservoir consists mainly of bioclastic wackestone and mudstone deposited below wave base. The middle portion is dominated by algal-peloidal grainstone and packstone deposited on an undulating sea floor. Algal clasts were derived from algal bioherms developed as mounds. Distribution of intraclasts corresponds to topographical high relief just below sea level. The uppermost part is composed of rudist-peloidal grainstone/packstone interbedded with peloidal-foraminiferal grainstone/packstone, which is associated with rudist bioherms developed as small banks/mounds.

Reservoir Facies

Fades Description

The Thamama II reservoir in the “A” field ranges in thickness approximately from 43 to 46 m (140 to 150 ft). Average porosity and permeability range from 25 to 30%, and 10 to 50 millidarcies, respectively. Stylolirization has occurred at certain horizons within the reservoir, forming five relatively tight layers that subdivide the reservoir into six units, i.e., IIA, IIB, IIC, IID, IIE, and IIF (Fig. 2). The tight layers are defined as “S” Zones: S1, S2, S3, S4, and S5, in descending order. They are correlative on porosity logs over the field, although no stylolites are recognized in S2 and S3 of some crestai wells. A typical seam is recognized in S5 of a thin and very tight layer, whereas low-amplitude stylolites are commonly developed in S1 to S4 in the grain-supported facies (units IIA to IID). Decrease of both porosity and permeability within “S” Zones is associated with stylolitic seams and cementation. Dolomite rhombs are variably present in the reservoir. Distinct dolomite bands are common within the middle of HE. In some areas, dolomites have completely replaced the original sediments. Reservoir lithofacies are summarized as follows.

Rudist-Peloidal Grainstone/Packstone (Units IIA and IIB in Part). —

This is the most distinctive facies in the reservoir, occurring commonly in unit IIA and the upper part of unit IIB. It is characterized by a large amount of fragmented and intact rudists, interbedded with fine-grained, peloidal-foraminiferal grainstone/packstone. Rudist fragments are concentrated at certain horizons. Rolled fragments of rudists are observed sporadically throughout the interval. This accumulation of rudist bivalves could have resulted from reworking, although locally intact rudists are also present. Most of the rudists are partially to extensively bored.

Algal-Peloidal Grainstone/Packstone (Units IIB, IIC, IID, and IIE in Part).—

This facies is characterized by diverse grain constituents with a wide variation in size and sorting. Most of the grains are bioclasts and peloids. The former is composed of whole or fragmented rudists, benthonic foraminifera, and algae (Lithocodium). Echinoderms, dacyclad algae, and gastropods are also present. Relatively large grains ranging from granule to medium pebble size, represented mainly by bioclasts, algal clasts, and intraclasts, are incorporated into a porous matrix composed of silt-to finegrained sized peloids. Generally, bioclastic grains show wide variation in size, ranging from very fine sand to pebble size. Granule-to small pebble-size bioclasts are commonly micritized. Algal patches and algal clasts are locally abundant. Intraclasts are the most distinct grains among these grain components because of their size and shape. Intraclasts are present in “matrix” composed of very fine-to medium-grained, well sorted peloids as loosely packed muddy fragments. The origin of these intraclastic grains is indeterminate because almost all have been extensively micritized. In addition to the above-described components, subrounded, very fine-to medium-sand-size and well-sorted, coarse-to very coarse-sand-size grains (peloidal/algal coated) are subordinate grain constituents. Most peloids may be micritized foraminfera and bioclasts.

Bioclastic Wackestone/Mudstone (Units IIE and 1IF).—

This lithofacies is distributed in the lowest part of the reservoir and is composed of wackestone and/or mudstone with scattered bioclasts and Orbitolina. Fine-grained bioclastic packstone is locally present. Porosity is present within the matrix as micropores and locally biomolds. Slight color mottling in texture caused by bioturbation, which is locally intense, is also recognized.

Significance of Sedimentological Features

Small-scale, upward-fining bed sets are mainly recognized within the algal-peloidal grainstone/packstone, representing the facies of units IIB, IIC, IID, and IIE in part. These bed sets are characterized by the presence of very coarse sand-to granule-size grains at the base and by the appearance of cyclic features with individual thickness ranging from a half meter to a few meters (Fig. 3). Each cycle fines upward to a very fine-to fine-grained grainstone/packstone. The upper portion of each bed set is biorurbated, and burrows are commonly observed. The top and base of each bed set are commonly bounded by an irregular surface, which could have resulted from submarine erosion (disconformity?). Tidal currents and/or wave agitation may have controlled sorting of coarser grainstone and packstone observed in the basal parts of the bed sets

Fig. 3.

—Plots of porosity vs. permeability for facies Types A, B, C, and F showing lithological controls on high-permeability facies.

Fig. 3.

—Plots of porosity vs. permeability for facies Types A, B, C, and F showing lithological controls on high-permeability facies.

High-Permeability Facies

The original sediments and subsequent diagenetic modification determine reservoir quality in the Thamama II reservoir. This section describes both lithological and diagenetic aspects controlling high-permeability facies in the reservoir.

Lithological Controls on High-Permeability Facies

Upward-Fining Sediments (Units IIB, IIC, IID, and IIE in Part).—

The cyclic, upward-fining bed sets are a significant sedimentary feature in the algal-peloidal grainstone/packstone lithofacies. Higher permeability tends to occur at the bases of these coarsegrained, algal-rich bed sets. This facies is subdivided based upon grain sorting and size. Type A is moderately to well sorted algal-peloidal grainstone. Type B is poorly to moderately sorted algal-peloidal grainstone. Type C is poorly sorted algal-peloidal grainstone/packstone. A schematic textural profile of high-permeability facies shows the relationship between these three facies types and porosity/permeability types (Fig. 3). The highest permeability values correspond to the better sorted facies, typically Type A, and also to the coarser facies at the bases of the upward-fining bed sets. Relatively high permeability in the bed sets is determined principally by grain sorting and grain size rather than by diage-netic modification.

Well Sorted, Very Fine-Grained Peloidal-Foraminiferal Grainstone (Unit I1A).—

This facies type is intercalated within the rudist-peloidal grainstone/packstone in unit IIA. This facies is defined as Facies Type F, and is characterized by well-sorted, very fine-to fine-sand-size peloids and micritized miliolids. Primary intergranular pores are well preserved with good pore connectivity resulting in enhancement of permeability (Fig. 3).

Diagenetic Modification of High-Permeability Facies

Sediments in the reservoir may have undergone many diagenetic processes since deposition, therefore their fabrics may have significant influence on reservoir quality. In general, deterioration of reservoir quality in the western area of the “A” field might be related to intense cementation by calcite, but porosity and permeability have been preserved in the eastern area of the field. This section summarizes several diagenetic events that have improved both porosity and permeability in association with main facies types.

Very Fine to Fine-Grained Algal-Peloidal Grainstone/Packstone (Units IIB, IIC, IID, and IIE in Part).—

Partial dissolution creating biomoldic and vuggy pores enhance permeability, although small equant calcite cements and large blocky calcite cements reduce permeability by occluding pores (Fig. 4). In addition, the upper parts of the upward-fining bed sets consist of very fine-to fine-grained algal-peloidal grain-stone/packstone facies Type D, which generally has poor permeability. However, the facies affected by dissolution show permeability improvement up to approximately a few hundred millidarcies.

Fig. 4.

—Plots of porosity vs. permeability for facies Types D and E showing diagenetic modifications on high-permeability facies.

Fig. 4.

—Plots of porosity vs. permeability for facies Types D and E showing diagenetic modifications on high-permeability facies.

Rudist-Peloidal Grainstone/Packstone (Unit IIA).—

Higher permeability corresponds to the presence and abundance of a secondary pore network. Preferential dissolution of rudists in facies Type E has created a secondary vuggy/moldic pore network, showing moderate to high permeability (Fig. 4). These secondary pores have enhanced pore connectivity, whereas the subsequent calcite cements, i.e., large blocky and small equant cements, have reduced the reservoir quality, although micropores and biomolds are still present. Finally, this facies is characterized by alternating low-permeability and high-permeability intervals as a result of these diagenetic processes.

Classification of High-Permeability Facies

Facies distribution and subsequent diagenesis control reservoir quality. The porosity profiles of the lower part of the reservoir (units IIE and IIF), composed of mud-supported facies, tends to decrease towards the base of the Thamama II reservoir (Fig. 2). The upper and middle parts (units IIA to IID), in contrast, display a consistent porosity profile resulting from the dominance of grain-supported facies except for sty lolitized layers (S1 to S5). On the other hand, permeability profile in the grain-supported fades is variable. The grain-supported interval has higher porosity and permeability than does in the mud-supported part. The reservoir is classified into nine main facies types in terms of permeability based on thin sections taken from 110 core samples, in which the following six types have been defined as significant high-permeability facies (Figs. 3 and 4).

  • Facies Type A (High-Permeability Facies)

    Lithology: moderately to well sorted algal-peloidal grairtstone

    Pore type: intergranular pores

    Permeability range: more than 1000 md

  • Facies Type B (Relatively High-Permeability Facies)

    Lithology: poorly to moderately sorted algal-peloidal grain-stone

    Pore type: intergranular and vuggy pores

    Permeability range: approximately from 50 md to 300 md

  • Facies Type C (Moderately High-Permeability Facies)

    Lithology: poorly sorted algal-peloidal grainstone/packstone

    Pore type: intergranular and vuggy pores

    Permeability range: approximately from 1 md to 200 md

  • Facies Type D (Relatively High-Permeability Facies)

    Lithology: very fine-to fine-grained algal-peloidal grainstone/packstone

    Pore type: intergranular and vuggy pores

    Permeability range: approximately from 1 md to 300 md

  • Facies Type E (Relatively High-Permeability Facies)

    Lithology: rudist-peloidal grainstone/packstone

    Pore type: vuggy and/or moldic pores

    Permeability range: approximately from 1 md to 1000 md

  • Facies Type F (Relatively High-Permeability Facies)

    Lithology: well sorted very fine-grained peloidal-foraminiferal grainstone

    Pore type: intergranular pores

    Permeability range: approximately from 50 md to 800 md

In addition to the above high-permeability facies, the following three facies have lower permeability values. However, both porosity and permeability vary in dolomite Type G, which locally has high permeability resulting from high connectivity in the intercrystalline pore network.

  • Facies Type G

    Lithology: dolomite and/or dolomitic limestone

    Pore type: intercrystalline pores

    Permeability range: approximately from 1 md to 100 md

  • Facies Type H

    Lithology: very fine-to fine-grained peloidal packstone (including stylolitized layers: S1 to S5)

    Pore type: intergranular pores

    Permeability range: approximately from 0.001 md to 10 md

  • Facies Type I

    Lithology: bioclastic wackestone/mudstone

    Pore type: matrix pores

    Permeability range: approximately from 0.01 md to 10 md

Continuity of High-Permeability Fades

Units IIB, IIC, and IID.—

The highest permeability in reservoir units IIB, IIC, and IID has a tendency to develop at the bases of the upward-fining cycles characterized by the relatively well sorted, coarse-sand-size grainstone with a dominant intergranular pore network. Such coarse grainstones vary in thickness from a meter ± to less than 30 cm, and tend to be more common in the eastern area of the field. However, they are difficult to correlate between wells. Judging from sedimentary features, this grainstone may locally have been deposited under high-energy conditions, as reworked sediments. These coarse grainstones consist mainly of algal grains that were possibly derived from relatively small-scale algal mounds. On the other hand, well sorted coarse grainstones are not generally recognized in the western area of the field, even though the upward-fining bed sets are present. This may indicate that subtle variation in depositional setting existed over the field. Diverse energy conditions of sedimentation can be inferred, compared with that of the eastern area, although the Thamama II reservoir was uniformly deposited under shallow-water conditions on a carbonate ramp (Alsharhan and Nairn, 1986). This interpretation is also based on evaluation of the available data and supports the idea that development of the better-permeability grainstone streaks is not continuous over the field and may be limited to the crestai area of the eastern part of the field.

Unit IIA.—

Rudist-peloidal grainstone/packstone in unit IIA is also an important nigh-permeability facies. Selective dissolution of the rudists occurred in locally discrete bands, and resulted in enhanced permeability, although subsequent coarse calcite cement partly fills these biomolds. The well sorted very fine-grained peloidal-foraminiferal grainstone having primary intergranular pores is a minor element. In addition, the intergranular pores in this facies are commonly filled by calcite cement. Thus, the reservoir characteristics of unit IIA faies are represented by heterogeneous rock with alternating low-permeability and high-permeability intervals. Considering all sedimentological and diagenetic features from both core observations and thin-section examination, it can be inferred that high-permeability facies in unit IIA are not laterally continuous over the field.

Pore Geometry in High-Permeability Facies

MICP Data Conversion to Pore-Throat Size Distribution

Carbonate reservoirs are characterized by complex pore systems, which are mainly categorized as primary and secondary pores. Pore geometry and its connectivity in a reservoir determine permeability. Although pore sizes, shapes, and connectivity are very complicated, mercury-injection capillary pressure data (MICP) provide useful information on the size of pores and throats. Capillary pressure curves indicate the percentage of total pores in the rock by plotting the mercury-injected volume against pressure. A pore-throat size distribution curve can be obtained from mercury-injection capillary pressure data. These pore-throat size distribution curves were also applied to categorize rock characteristics in this study. A total of 239 mercury-injection capillary pressure measurements from 23 wells represent all reservoir zones. Pore-throat size for each capillary pressure data set was calculated using the following formula, which was developed by Core Laboratories Inc. in 1982:

Ri = 2Tcosh(C/Pc)

where Ri = pore-throat radius (pm); T = air-mercury interfacial tension (= 480 dynes/cm); h = air-mercury constant angle of 140°; C = unit conversion constant (= 0.145); Pc = mercury-injection capillary pressure (psia).

Classification of Pore-Throat Size Distribution Curves

The mercury-injection capillary pressure data were converted into pore-throat size distribution using the equation above. Porethroat size distribution curves are classified into seven types types based on curveshapes and peak location ofpthororaet size The pthororaet size distribution classes (Figs 5 and 6) and are de scribed as follows:

Fig. 5.

—Classification of pore-throat size-distribution curves by plots of percent probability density to pore-throat size.

Fig. 5.

—Classification of pore-throat size-distribution curves by plots of percent probability density to pore-throat size.

Fig. 6.

—Permeability range of each pore-throat size-distribution curve type.

Fig. 6.

—Permeability range of each pore-throat size-distribution curve type.

  • Curve Type 1 (unimodal; 58 samples): Maximum probability density is higher than 10%, and the peak pore-throat size is located at less than 1 μm. Permeability ranges from 0.02 to 17 md.

  • Curve Type 2 (unimodal; 91 samples): Maximum probability density is lower than 10%, and the peak pore-throat size is located at less than 1 pm. Permeability ranges from 0.05 to 25 md.

  • Curve Type 3 (unimodal; 35 samples): The peak pore-throat size located at a point higher than 1 μm. Permeability ranges from 2.6 to 127 md.

  • Curve Type 4 (unimodal; 18 samples): The distribution is symmetrical around 1 pm and has a broad curve shape. Permeability ranges from 4.4 to 44.7 md.

  • Curve Type 5 (bimodal; 22 samples): Two peaks are recognized. One peak is at less than 1 pm and the second is greater than 1 pm. Permeability ranges from 4.7 to 1544 md.

  • Curve Type 6 (trimodal; 8 samples): Three peaks are observed and the curve shape is very broad. Permeability ranges from 19.9 to 245 md.

  • Curve Type 7 (flat; 6 samples): The curve shape is almost flat. Permeability ranges from 0.003 to 17.2 md.

In general for the Thamama II reservoir, as permeability increases, the curves become wider and the location of the distribution peak moves towards larger pore-throat size. Almost of all of the low-permeability samples show similar single peak curves with the peak at less than 1 pm. Each pore-throat size curve type has range of permeability (Fig. 6). Curve Types 1 and 2 show lower permeability ranges. Generally, low-permeability samples with less than 10 md are classified into either Curve Types 1 or 2. Curve Types 3, 4,5, and 6 indicate relatively high permeability, and they can be roughly distinguished as two groups, a unimodal system (Curve Types 3 and 4) and a bimodal or trimodal system (Curve Types 5 and 6). On the other hand, many high-permeability samples have different curve types The difference between curvetypes results from characteristics of the pore network of each facies.

Interpvelation of Pore Geometry and Facies/Layers

Relationship between Pore-Throat Size Distribution Curve Types and Facies

An attempt was made to describe the pore geometry systems in the reservoir, especially in the high-permeability facies, after pore systems were classified comprehensively with emphasis on their genetic aspects. Based upon availability of thin sections, 99 mercury injection samples from 8 wells were used to clarify the relationship between facies type and pore geometry (Table 1). The relationships between facies and pore-throat size distribution curves are summarized as follows (Fig. 7).

Table 1.

—Numbers of sample of each curve type in each facies type

Pore-throat size distribution curve types
Type 1Type 2Type 3Type 4Type 5Type 6Type 7Subtotal
Facies types
Type A 
TypeB 
Type C 16 
Type D 
Type E 
Type F 
Type G 
Type H 19 23 47 
Type I 10 
Subtotal 24 36 10 10 Total 99 
Pore-throat size distribution curve types
Type 1Type 2Type 3Type 4Type 5Type 6Type 7Subtotal
Facies types
Type A 
TypeB 
Type C 16 
Type D 
Type E 
Type F 
Type G 
Type H 19 23 47 
Type I 10 
Subtotal 24 36 10 10 Total 99 
Fig. 7.

—Relationship between facies types and pore-throat size-distribution types.

Fig. 7.

—Relationship between facies types and pore-throat size-distribution types.

Facies Type A (moderately to well sorted algal-peloidal grainstone): The mercury-injection data for this type are not available. Intergranular pores are the main visible pore type.

Facies Type B (poorly to moderately sorted algal-peloidal grainstone): Curve Types 5 (33.3%) and 6 (66.7%) are mainly found for this facies, in which both intergranular and vuggy pores are preserved as the main visible pore types. In particular, a large-sized intergranular pore network is well developed. In addition, micropores are probably present in the grains because the pore-throat size distribution curves with bimodal and/or trimodal shapes may indicate existence of more than two types of pores in the facies.

Facies Type C (poorly sorted algal-peloidal grainstone/packstone): Curve Types 1 (18.8%), 2 (50%), and 4 (18.8%) are the representative types for this facies. The grains of the facies are poorly sorted, and most pore spaces among large grains are filled with more fine grains and/or micrite as matrix. Most of the grains are affected by micritization, as in facies Type B. Therefore, pore-throat size distribution curves indicate a small pore throat. Intergranular and vuggy pore networks are partially preserved and, contribute to better permeability.

Facies Type D (very fine-to fine-grained algal-peloidal grainstone/packstone with vuggy pores): Curve Type 5 (62.5%) is the main type for this facies, but, Curve Types 21(12.5%), 4(12.5%), and 6(12.5%) are also observed. This facies is affected by dissolution, and the large-sized pore network is formed partly by vuggy pores. Furthermore, micropores in the micritized grains and micritic matrix are possibly enlarged by leaching.

Facies Type E (rudist-peloidal grainstone/packstone): Curve Types 2 (42.9%), 6(28.6%), are the main types for this facies. and 6 (12.5%) are also observed. This facies is affected by dissolu-Here, Curve Type 3 indicates the existence of small intergranular pores. However, according to observations on the slabbed cores, this facies is characterized by a relatively large secondary pore network caused by preferential dissolution of rudist bivalves. It should be noted that the individual plug samples used for measurement might not reflect the nature of the entire pore system.

Facies Type F (well sorted very fine-grained peloidal-fora-miniferal grainstone): Curve Type 3 (80%) is the main type for this facies. The grains of this facies are well sorted, and small inter-granular pores are well preserved as the main visible pore type.

Facies Type G (dolomite and/or dolomitic limestone): Pore-throat size distribution Curve Type 3 (100%) is the only type in this facies, and suggests the existence of intercrystalline pores.

Facies Type H (very fine-to fine-grained peloidal packstone, including stylolirized layers: S1 to S5): The main pore type is microporous, and most pore-throat size distribution curves are Curve Type 1 (40.4%) or Curve Type 2 (48.9%).

Facies Type I (bioclastic wackestone/muds tone) : Curve Types 2 (40%) and 7 (40%) are the main types for this facies. Most of the pores are micropores.

As described above, each facies is characterized by a unique pore-throat size distribution(s) resulting from its own pore network. Some facies, however, have the same pore-throat distribution. This indicates the same perrophysical characteristics, even though the facies type is different. The main pore types for each facies and their relationship to permeability and pore-throat size distribution are illustrated in Figure 8.

Fig. 8.

—Relationship between facies types and pore geometry/permeability.

Fig. 8.

—Relationship between facies types and pore geometry/permeability.

Relationship between Pore-Throat Size Distribution Curve Types and Layers

Each reservoir sublayer is characterized by a specific proportion of pore-throat size distribution curve types (Fig. 9 and Table 2). Curve Type 2 dominates units IIA to 1ID. Below IID, Type 2 is also common, but Curve Type 1 is the most prevalent. Curve Type 3 appears mainly in units IIA and HE. Although the frequency of Curve Types 4, 5, and 6 is low, these types commonly appear in association with high-permeability facies in units IIA to IID. SI and S5 include Curve Type 7. ín general, Curve Types 1 and 2 increase for “S” zones compared with sublayers immediately above and below. The features of each layer are summarized as follows:

Table 2.

—Numbers of sample of each curvetype in each reservoir layer.

Pore-throat size distribution curve types
Type 1Type 2Type 3Type 4Type 5Type 6Type 7Subtotal
Reservoir layers
IIA1 10 
I1A2 15 
IIA3 
11A4 22 
S1 
IIBI1 13 
IIB2 
IIB3 
S2 
IIC1 12 
I1C2 
IIC3 12 
S3 
IID1 12 
IID2 13 14 31 
11D3 
S4 12 
IIE1 12 
IIE2 11 
IIE3 
S5 
IIF 11 
Subtotal 58 91 35 18 22 Total 239 
Pore-throat size distribution curve types
Type 1Type 2Type 3Type 4Type 5Type 6Type 7Subtotal
Reservoir layers
IIA1 10 
I1A2 15 
IIA3 
11A4 22 
S1 
IIBI1 13 
IIB2 
IIB3 
S2 
IIC1 12 
I1C2 
IIC3 12 
S3 
IID1 12 
IID2 13 14 31 
11D3 
S4 12 
IIE1 12 
IIE2 11 
IIE3 
S5 
IIF 11 
Subtotal 58 91 35 18 22 Total 239 
Fig. 9.

—Relationship between reservoir layers and pore-throat size-distribution types.

Fig. 9.

—Relationship between reservoir layers and pore-throat size-distribution types.

  • Unit IIA: This is characterized by a high proportion of Curve Types 2 and 3. Curve Types 1, 5, and 6 are a minor constituent. The main high-permeability facies in unit HA are Facies Types E and F.

  • Unit IIB: This is characterized by Curve Types 2 and 5. Especially, the lower part (unit IIB3) is characterized by a high proportion of Curve Type 5. Facies Types B, C, and D are the main high-permeability facies in unit IIB, and pore geometry is characterized by bimodal or trimodal distributions.

  • Unit IIC: This is also characterized by Curve Types 2 and 5, and the high-permeability facies of unit IIC consists mainly of Facies Types B, C, and D. In particular, the upper part (unit IIC1) and lower part (unit IIC3) are characterized by a high proportion of Curve Type 5, with a bimodal system. On the other hand, the middle part (unit IIC2) consists mainly of Curve Types 3 and 4.

  • Unit IID: The upper part of unit IID is composed of various curve types, whereas Curve Types 1 and 2 are the main constituents of the middle part of unit HD. No data are available for the lower part of unit IID.

  • Unit HE: The middle part of unit IIE is characterized by Curve Type 3, whereas the upper (unit IIE1) and lower (unit IIE3) parts are dominated by Curve Types 1 and/or 2.

  • Unit IIF: This is composed mainly of Curve Types 1 and 2.

As mentioned above, a reservoir sublayer is not represented by a specific pore-throat size distribution curve type but a combination of curve types. This may indicate that the pore-throat size distribution of a specific sublayer is characterized by specific, high-permeability facies types. In addition, the pore-throat size distribution curve is determined by the permeability range, which shows lateral variation in the sublayer. It is important to establish a pore-throat size distribution curve for a specific sublayer, because the seven curve types of pore-throat size distributions have different pore geometries and exhibit distinctive and characteristic capillary pressure curve shapes.

Reservoir Simulation

Some porous zones in the eleven-layer scheme, which have been defined on the basis of porosity profiles, are further subdivided on the basis of log curve profiles and lithology, especially vertical and lateral distribution of high-permeability facies characterized by a pore-throat size distribution(s). A total of twenty-two sublayers are identified, e.g., unit IIA subdivided into four sublayers and units IIB, IIC, IID, and IIE each subdivided into three sublayers.

Each layer of the 22 sublayer scheme is categorized by a specific relationship between porosity and permeability (Fig. 10). This relationship can be applicable to permeability prediction of non-cored intervals and wells. Furthermore, a single pore-throat size distribution curve is selected on the basis of the permeability range in the specific sublayer of this 22 sublayer scheme to assign a specific capillary pressure to a reservoir simulation model. Finally, rock types are assigned using lithological, petrographi-cal, and diagenetic and mercury-injection curve character.

Fig. 10.

—Plots of porosity vs. permeability for each reservoir layer.

Fig. 10.

—Plots of porosity vs. permeability for each reservoir layer.

Conclusions

The Thamama II reservoir is classified into nine facies by lithology and permeability, in which six high-permeability facies are identified. Both original sediments and diagenetic modification control high permeability in these facies. High permeability in the algal-peloidal grainstone/packstone, which is characterized by fine-scaled, cyclic upward-fining bed sets, tends to be developed in the basal part of the bed sets and determined by grain size, shape, and sorting. High permeability in the rudist-peloidal grainstone/packstone is related to preferential dissolution of rudists.

These high-permeability facies are not laterally continuous over the field. In particular, well sorted, coarse grainstone in the basal parts of the bed sets, which are considered to have an important role on water breakthrough, may be limited to the crestai area of the eastern part of the field.

Pore-throat size distribution curves are classified into seven representative types, Curve Types 1 to 7, based on curve shapes. Curve Types 3, 4,5, and 6 indicate relatively high permeability, and they can be roughly distinguished as a unimodal system (Curve Types 3 and 4) or a bimodal/trimodal system (Curve Types 5 and 6). Bimodal/trimodal curve types show a higher permeability range than the unimodal system. Almost all low-permeability samples (< 2 md) show similar single peak curves, with the peak lower than 1 μm.

Each facies type is characterized by a unique pore-throat distribution. High-permeability samples (> 100 md) in units IIB, I1C, and I1D are characterized by either bimodal or trimodal pore systems. In units HA and UE, some high-permeability samples show unimodal and bimodal pore systems. Curve Type 2 is the most prevalent of the seven curve types in units IIA to IID. On the other hand, Curve Types 1 and 2 are common in units IIE and IIF.

The eleven-layer scheme, previously defined on the basis of porosity profiles, was further divided into sublayers based on log curve profiles, vertical and lateral distribution of high-permeability facies, and pore-throat size distribution curve types. A total of 22 sublayers were defined. A single pore-throat size distribution curve can be assigned for each sublayer according to facies distribution and permeability range. As a result, the relationship between porosity and permeability for each of the 22 sublayers is well characterized and will be applied to appropria te simulation modeling.

References

Alsharhan
,
A.S.
,
1990
, Geology and reservoir characteristics of Lower Cretaceous Kharaib Formation in Zakum Field, Abu Dhabi, United Arab Emirates, in
Brooks,
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Capillary pressure effect on injected water movement and upscales relative permeability in a heterogeneous carboante reservoir
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Acknowledgments

The authors are grateful to the management of the Abu Dhabi National Oil Company and the Zakum Development Company for permission to publish this paper. Thanks are also expressed to Japan Oil Development Co., Ltd. (JODCO) for support in preparing this manuscript. The authors are grateful to Mr. K. Nishi for comments and advice during the reservoir characterization study. We also very much appreciate the assistance and discussions from the Technical Department staff of JODCO during the study, and to the editors of this publication for final editing and suggestions to improve our paper.

Figures & Tables

Contents

GeoRef

References

References

Alsharhan
,
A.S.
,
1990
, Geology and reservoir characteristics of Lower Cretaceous Kharaib Formation in Zakum Field, Abu Dhabi, United Arab Emirates, in
Brooks,
,
J.
,
ed.,
Classic Petroleum Provinces
 :
Geological Society of London
, Special Publication
50
, p.
299
316
.
Aisharhan
,
A.S.
,
Nairn
,
A.E.M.
,
1986
,
A Review of the Cretaceous Formations in the Arabian Peninsula and Gulf: Part 1. Lower Cretaceous (Thamama Group): Stratigraphy and Paleogeography
:
Journal of Petroleum Geology
 , v.
9
, p.
365
392
.
Hassan
,
T.H.
,
Mudd
,
G.C.
,
Twombley
,
B.N.
,
1975
,
The stratigraphy and sedimentation of the Thamama Group (Lower Cretaceous) of Abu Dhabi
:
9th Arab Petroleum Congress, Dubai, United Arab Emirates,
  p.
1
11
.
Murris
,
R.J.
,
1980
,
Middle East Stratigraphic evolution and oil habitat
:
American Association of Petroleum Geologists, Bulletin
 , v.
64
, p.
597
618
.
Nishi
,
N.
,
Shibasaki
,
T.
,
1996
,
Capillary pressure effect on injected water movement and upscales relative permeability in a heterogeneous carboante reservoir
:
7th Abu Dhabi International Petroleum Exhibition and Converence, Proceedings, SPE 36177
 , p.
26
36
.

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