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Dynamics of cementation in response to oil charge: Evidence from a Cretaceous carbonate field, U.A.E.
Sedimentary Geology 228 (2010) 246–254
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Sedimentary Geology j o u r n a l h o m e p a g e : w w w. e l s ev i e r. c o m / l o c a t e / s e d g e o
Dynamics of cementation in response to oil charge: Evidence from a Cretaceous carbonate field, U.A.E. P.A. Cox a,b,⁎, R.A. Wood a,b, J.A.D. Dickson c, H.B. Al Rougha d, H. Shebl d, P.W.M. Corbett b,e a
School of GeoSciences, University of Edinburgh, Kings Buildings, West Mains Road, Edinburgh, EH9 3JW. UK Edinburgh Collaborative of Subsurface Science and Engineering, UK Department of Earth Sciences, University of Cambridge, Downing Street, Cambridge, CB2 3EQ, UK d ZADCO, Abu Dhabi, United Arab Emirates e Institute of Petroleum Engineering, Heriot-Watt University, Riccarton Campus, Edinburgh, EH14 4AS, UK b c
a r t i c l e
i n f o
Article history: Received 1 December 2009 Received in revised form 28 April 2010 Accepted 29 April 2010 Available online 17 May 2010 Editor: B. Jones Keywords: Carbonate Diagenesis Calcite cements Oil charge Abu Dhabi Oxygen isotopes Microporosity
a b s t r a c t Oil charge is thought to inhibit the growth of cements within subsurface pore systems. We explore this phenomenon in a giant Cretaceous carbonate field from U.A.E., where the oil-filled crest porosity ranges from 10 to 50% and permeability from 0.08 to 830 mD but coeval water leg porosity is reduced to 10 to 23% and permeability to 0.1 to 4 mD. Only 5% of primary interparticle pores (N 30 μm diameter) in the crest are fully cemented, compared to 99% of pores in the water leg. Syntaxial calcite burial cements (N 10 μm diameter) in the oil leg show 12 cathodoluminescence zones with oil inclusions (n = 27) occurring in four of the five final zones. Mean in-situ ion microprobe δ18OVPDB data from the oil leg cements range from −1.2‰ in the oldest zone decreasing to −10.3‰ in zone 11, returning to −7.7‰ in the final zone. The oldest distinguishable cement zone in the water leg shows highly variable δ18O from −3.6‰ to −9.3‰ with a mean of −7.3‰, and with subsequent zones decreasing to a mean value of −9.4‰ for the youngest cement zone. Decreasing δ18O values are interpreted as indicating increasing temperature reflecting burial and the evolution of pore water composition: broadly similar trends in the oil and water legs suggest precipitation under the same general conditions. Unlike the oil leg cements, the final zone in the water leg occludes nearly all remaining pore space. The δ18OVPDB of bulk micrite from the water leg shows an average of −7.4‰ (n = 9) compared to −6.2‰ (n = 10) from the oil leg, suggesting the precipitation of further micrite cement at greater burial depths. We infer that burial cementation slowed in the presence of oil due to a reduction of potential nucleation sites as well as porewater and solute movement within weakly oil-wet pores, whereas continued flow and solute movement through all pores including the micropores (b 10 μm diameter) enabled extensive cementation in the water leg. © 2010 Elsevier B.V. All rights reserved.
1. Introduction Pore space in sedimentary rocks is known to decrease regularly with increasing burial depth but subsurface oil reservoirs are a notable exception to this pattern (Robinson and Gluyas, 1992; Emery et al., 1993). Oil reservoirs have greater porosity than their depth would indicate because they contain less cement than the surrounding rocks. When oil fills pores in sediments, water is partially displaced, and, as water is the medium for diagenetic reactions, cementation is inhibited or retarded (Worden et al., 1998; Heasley et al., 2000). Cementation and oil migration are thought to occur synchronously (Gluyas et al., 1993), but the oil-filling of reservoirs is a gradual
⁎ Corresponding author. School of GeoSciences, University of Edinburgh, Kings Buildings, West Mains Road, Edinburgh, EH9 3JW. UK. Tel.: +44 131 6506014; fax: +44 668 3184. E-mail address: [email protected] (P.A. Cox). 0037-0738/$ – see front matter © 2010 Elsevier B.V. All rights reserved. doi:10.1016/j.sedgeo.2010.04.016
process where pores in the crest are filled first (Marchand et al., 2001). Cement growth will therefore cease or slow initially in the crest and continue down the structure until the final oil/water contact is reached. Below the oil/water contact cementation can continue as long as conditions are right for precipitation in the water-saturated pores and space exists into which cement can grow. In both quartzcemented sandstone reservoirs (Walderhaug, 1990; Bjørkum et al., 1993; Emery et al., 1993) and calcite-cemented carbonate reservoirs (Neilson et al., 1996, 1998), cements within the oil leg contain inclusions of oil, indicating that they grew in pores that contained both water and oil. The retardation of quartz cement growth by the presence of oil has been modelled by Walderhaug (1994, 1996) and applied by Marchand et al. (2001, 2002) to North Sea fields that took N 15 Ma to fill with oil. The notion that cement growth and oil charge occur synchronously over millions of years during burial means that the conditions under which the cements grow are likely to change. Temperature will rise and formation waters evolve through reactions with the rocks
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during burial and with the passage of time. These changes should be reflected in the chemistry of the cement. The elemental chemistry of calcite is affected by many factors and is difficult to interpret (Richter et al., 2003) whereas the control of stable isotope composition is better understood. Calcite precipitated during burial will experience rising temperature with increasing depth, leading to progressively lower δ18OVPDB values. The δ18O evolution of formation waters is variable but commonly becomes greater due to calcite dissolution/re-precipitation reactions (Lawrence, 1988). Although these effects may cancel one another out, many analyzed late calcites show decreasing δ18OVPDB values related to increasing temperature during burial (Hudson, 1977). Carbonate rocks were collected from the Lower Cretaceous (late Hauterivian–late Barremian: 124–120 Ma) Kharaib Formation of the ‘Thamama’ Group, from a giant anticlinal oil field, offshore U.A.E. (Fig. 1A). The ‘Thamama’ Group is an informal title and encompasses the uppermost part of the Sahtan Supersynthem, the entire Kahmah Supersynthem, and the lowermost portion of the Wasi'a Supersynthem (Granier et al., 2003). The ‘Thamama’ Group contains the Habshan, Lekhwair, and Kharaib Formations, followed by the Hawar Member and finally the Shu'aiba Formation (Fig. 2). All these units were defined by subsurface data correlated throughout the southeastern Arabian Gulf, and are bounded by unconformities (Granier, 2000). They are often, but not always, bounded by transgressive surfaces that often coincide with sequence boundaries (Granier et al., 2003). The Kharaib Formation was deposited in a distal carbonate ramp setting and consists of a series of stacked reservoirs that follow 4th order high frequency sequences (Alsharhan et al., 1991). The Kharaib Formation lithology consists of mudstones–packstones–rudstones with dominant interparticle and microporosity. Lithologies are concentrated in the orbitilinid foraminiferan Palorbitolina lenticularis, the rudist Glossomyphorus costatus and various dasycladacean algae. The formation shows minimal laterally facies variation across the
247
Fig. 2. Early–Middle Cretaceous stratigraphy of the ‘Thamama’ Group in U.A.E. (modified from Immenhauser et al., 2004).
entire offshore field and therefore between the water and oil legs within the field crest and flanks. The lowermost ∼ 2–3 m of the Lower Kharaib Formation is muddy, containing only echinoid fragments and Palorbitolina lenticularis. The Kharaib Formation was uplifted at 92 Ma (Sharland et al., 2001) as the Semail Ophiolite obducted onto the north western Arabian plate margin creating a series of low-angle domes trending northwest to south east (Fig. 1B). This tectonism activated movement of the Precambrian Ara salt layers below that further amplified these structures (Al-Barwani and Mclay, 2008). The field is faulted and fractured (Tamura et al., 2004; Edwards et al., 2006; Edwards, 2006). The main source of oil was the Shu'aiba basinal facies that is thought to have reached maturity during the late Cretaceous (Murris, 1980; Oswald et al., 1995; Milner, 1998) around or shortly after the onset of uplift and the start of trap formation (Gumati, 1993). The main phase of oil charge within the Kharaib Formation has been constrained to the late Eocene (Taher, 1997). Stylolites are common in the Kharaib Formation, and are parallel to bedding indicating a dominant vertical lithostatic stress. Welldeveloped stylolite levels show lower porosity and permeability due to enhanced chemical compaction with accompanying solutiontransfer cementation. Stylolites formed preferentially in the water leg (Oswald et al., 1995), but are also present in the oil leg reservoir facies and ubiquitous in muddy, dense facies in the lower section of reservoir cycles where alumino-silicate minerals probably catalysed pressure dissolution (Ehrenberg, 2003). Stylolitization is thought to have commenced after 600 m of burial at temperatures of approximately 65.6 °C (Oswald et al., 1995). Predictions as to the retardation of cementation and therefore retention of high porosity due to oil charge have been applied to calcite cement growth in Cretaceous reservoirs from Abu Dhabi (Kirkham et al., 1996; Neilson et al., 1998). Here we use δ18O data derived from in-situ ion microprobe measurements to explore the dynamic relationship between cement growth and oil emplacement. 2. Samples and methods
Fig. 1. A) Map showing the major ‘Thamama’ Group oil fields of U.A.E. (modified from Granier et al., 2003); B) the tectonic setting after 92 Ma, involving the Semail Ophiolite obduction and doming of Precambrian salts causing antiformal structures which now host many offshore and onshore oil fields surrounding Abu Dhabi (modified from Sharland et al., 2001).
All samples are rudist-orbitolinid packstones and rudstones collected from the same reservoir horizon from one cored well from the crest (oil leg) and one cored well from the western flank (water leg) of the field. The distance between the two wells is ∼20 km. The oil leg core measures ∼22 m and the water leg core 76 m. Ten 2″ by 3″ thin sections were analyzed from each well. Oil leg samples are at a current burial depth ∼220 m above the water leg samples. Calcite cements precipitated from both marine and meteoric waters are found in these rocks but only macrocements (N10 μm diameter) that crystallized from formation waters during burial are considered here. These macrocements occur in every
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sample and volumetrically dominated cementation. The relative cementation of primary interparticle pores N30 μm diameter was quantified by point-counting from blue epoxy-impregnated standard thin sections. Porosity and permeability data of the oil and water leg were measured commercially via mercury-injection from adjacent petrophysical plugs. A Leitz Metallux Leica 3 microscope, with a 100 W Hg HBO 103 W/ 2 bulb and a blue filter creating UV light with a waveband of 440– 490 nm was used to locate oil inclusions. All counted inclusions were assessed to be primary and contained a non-luminescent portion reflecting the presence of a vapour bubble. Inclusions close to fractures or cleavage planes were discounted as these may have been emplaced at any period during burial and so provide no information about oil charge relative to cementation. Powders of sample size 0.03–0.2 mg were extracted for isotope analysis from thin sections using a tungsten steel needle under a Leica 240 microscope. Areas of micrite lacking visible bioclasts or other grains were targeted. Powders were dissolved at 25 °C with 100% phosphoric acid followed by conventional mass spectrometry using a Thermo Electron Delta + Advantage. Results are reported as deviations from VPDB standard (‰) and precision was measured at a level better than 0.1‰ for δ13C and δ18O. Small rock chips were broken from core samples for SEM examination. Chips were cleaned in an ultrasonic tank, attached to aluminum stubs, gold-coated, and imaged using a Phillips XL30CP SEM in secondary electron mode. A 20Kv, 6 μm diameter electron
beam was used to image at 120× magnification and reduced to 4 μm in diameter at magnifications above 1950×. Syntaxial cements growing upon echinoid fragments were selected as these contain both the earliest cement zones and final zones abutting against pore space indicating preservation of the final, youngest cement growth. A Catholuminescence Cold cathode CITL 8200 MK3A was used to identify cement zones separated by differing luminescence (Mason and Mariano, 1990; Habermann et al., 1996, 1998). This formed the basis for establishing cement stratigraphies in the water and oil legs (Braithwaite, 1993). Three rock chips from each well were analysed from the Lower Kharaib Formation. Samples were gold-coated and placed within the Cameca 1270 Ion Microprobe to gain in-situ δ18O measurements for individual cement zones. A 10–15 µm diameter Cs ion beam was used to ablate 10–15 µm diameter spots from the sample. The internal precision for each spot ranges between 0.009 and 0.015 (% Standard Error). The external precision was estimated to be 0.4‰ as determined by consecutive analysis of a UWC (University of Wisconsin Calcite) standard that was assessed to be homogenous. All analyses were standardized against the UWC which was performed before each analysis within a separate holder. This decreased the accuracy of the method, but relative variations are believed to be precise to 0.4‰ (external precision of the UWC). For each syntaxial overgrowth a single transect was completed from the oldest, innermost cement adjacent to the echinoderm
Fig. 3. Porosity and permeability plot for the oil- and water leg within a single reservoir horizon of the Kharaib Formation, ‘Thamama’ Group, U.A.E. photomicrographs of A) the oil leg, showing relatively high porosity and permeability with retention of interconnected macropores and mesopores, and B) the water leg with near complete macropore and mesopore occlusions by cementation. Scale bar = 1 mm.
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Fig. 4. Secondary electron images of A, B, oil leg, and C, D, water leg. A) Open mesopores with burial macrocements. B) Euhedral microrohombic fabric with microporosity. C) Occluded mesopores, and D) Compact anhedral fabric with limited microporosity. A,C, Scale bar = 20 μm, B,D, Scale bar = 10 μm.
fragment to the youngest outermost cement abutting an open pore. This allowed δ18O values and trends through the macrocements to be compared regardless of zone colour and luminescence characteristics. Eight transects were performed across eight syntaxial cements: four syntaxial cements were analysed from each thin section, using one thin section each from the oil and water legs. 3. Results Oil crest sample porosity ranges from 10 to 50%, and permeability from 0.08 to 830 mD (Fig. 3). By contrast, water leg samples occupy a distinct field of lower porosity and permeability values of 10 to 23%, and 0.1–4 mD, respectively. Of a total of 247 primary interparticle pores N30 μm in the oil leg, only 13 were fully occluded by cement (5%). Of 865 interparticle pores in the water leg, 861 were fully cemented (99%). The oil leg retains many open macropores (N30 µm
in diameter) and mesopores (30–10 µm in diameter) in open communication leading to relatively high porosity and permeability (Figs. 3A and 4A). By contrast, water leg cements occlude nearly all macro- and mesopores pores (Figs. 3B and 4C). SEM imaging shows that micrite is represented by equant crystals and in the oil leg these form either compact anhedral, or subhedral to euhedral microrhombic fabrics. Crystals are 2–5 μm in compact anhedral, and 3–12 μm in microrhombic fabrics. Microrhombic micrites present an open texture (Fig. 4B) with micropores (defined as pores b10 μm diameter, Cantrell and Hagerty, 1999). By contrast, no euhedral microrhombic fabrics are found in the water leg, and the incorporation of smaller crystals within larger ones and the presence of isolated larger crystals indicate a second generation of microspar growth with limited microporosity (Fig. 4D). Cathodoluminescence revealed 12 zones in the oil leg and 7 zones in the water leg syntaxial cements (Fig. 5). The final, youngest zone
Fig. 5. Cathodoluminescence images of syntaxial cements (C), nucleating on echinoderm fragments (E) within, A) water leg, and B) oil leg. Note the differences in cement zone thicknesses, and how the final zone in the water leg sample occludes all remaining pore spaces. The black/blue areas on both images reflect open pores. Scale bar = 0.5 mm.
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Table 1 δ18O and δ13C data for bulk micrite. Water leg
Oil leg
δ13C
δ18O
δ13C
δ18O
2.643 2.824 2.978 3.152 3.089 3.27 2.789 3.201 3.283
−7.318 −7.932 −7.51 −7.267 −7.717 −7.489 −7.421 −7.414 −6.075
3.362 2.897 2.948 2.963 3.152 2.906 3.123 3.247 3.312 3.405
−5.522 −5.522 −5.938 −6.905 −6.64 −6.965 −6.677 −6.676 −6.403 −4.714
present in the water leg zone commonly occludes most remaining pore space within the surrounding matrix (Fig. 5A). A total of 27 oil inclusions were found in 4 syntaxial cements within the oil leg samples, in zones 8, 9, 10 and 12 (Table 2A). Oil inclusions measure between 1 and 5 µm in diameter and fluoresce pale apple-green indicating moderate maturity. Table 1 and Fig. 6 present δ18O and δ13C data from bulk micrite samples from the oil and water legs. The δ18OVPDB of bulk micrite from the water leg shows an average of −7.4‰ (n = 9) compared to −6.2‰ (n = 10) from the oil leg. Ion Microprobe in-situ δ18O data for each transect are shown in Fig. 7. Transects do not sample every cathodoluminescence zone, but include either the oldest or youngest zones. Data are presented in Table 2 according to zone, and the mean value for each zone with variance is presented in Fig. 8. δ18O data obtained from syntaxial cements range from −10.3‰ to −1.2‰. Most transects in both water and oil legs show a broad trend of decreasing δ18O from the oldest to youngest cements. Within the oil leg, some zones present a large range in values commonly showing clear trends of progressive negativity with decreasing age within a single zone; other zones show little variability. The early stages of the water leg zones show considerable variability in values. This may be due in part to the fact that many are less than 10 µm thick and cannot be adequately sampled individually with a 10–15 µm diameter ion beam. The entire range of δ18O values (∼ −10‰ to ∼ −1‰) was not found in any single pore or sample and complete sequences are deduced from several samples. In the oil leg, the earliest cement zone shows a mean value of −1.2‰, and following zones show a steady decrease
Fig. 6. Scatter plot of δ13C/δ18O for bulk micrite samples from water and oil legs. The δ18OVPDB of bulk micrite from the water leg shows an average of −7.4‰, compared to −6.2‰ from the oil leg.
down to −10.3‰ in zone 11. The final cement zone shows a return to a less negative δ18O value of −7.7‰. The oldest cement zone in the water leg shows highly variable δ18O, from −3.6‰ to −9.3‰ (n = 7), with a mean value of −7.3‰. Subsequent zones show consistently negative values decreasing to a value of −9.4‰ for the youngest cement zone. 4. Cementation and burial Several authors have suggested that oil may progressively displace porewater and retard cementation (e.g. Heasley et al., 2000; Neilson et al., 1996, 1998). Here, the number of oil inclusions is highest in zone 8 of the oil leg cements (mean δ18O value of −5‰) but decreases towards the youngest zone. This confirms that the main oil charge was followed by further cement growth within presumably partially oilwet pore systems. The correspondence of increasingly negative in-situ δ18O values with decreasing age within a single CL zone and disparities between adjacent sequences indicates that zones with the same luminescence characteristics may not necessarily have been precipitated within either stable or indeed similar conditions. Colour zonation cannot be used to correlate between the oil and water legs or as proof of time equivalence. The absence of more positive values in the early zones of the water leg zones may be an artefact and reflects the difficulty of sampling individual zones b10 μm in diameter. The variation in δ18O values from proximal to distal growth increments of cement crystals (Fig. 7) indicates that conditions changed during precipitation. This is most simply explained as due to rising temperature as a result of progressive burial. The δ18O values are consistent with mineralogical stabilisation of marine fluids under deep burial conditions. δ18O values of calcite precipitated at equilibrium are controlled by temperature and the δ18O composition of the water that can be expressed in the following equation (Kim and O'Neil, 1997): 3 −1 1000 InαðcalcitewaterÞ = 18:03 10 T –32:42 δ18O values of −7‰ to −1‰ using estimates of temperature of 20 °C for seawater and 50 °C for shallow burial waters indicates that the δ18O composition of the water may have varied between −6‰ and +5‰ (SMOW). The average value for cements with these δ18O values indicates precipitation from water with δ18O = O‰. This is high for a Lower Cretaceous greenhouse ocean. A water temperature of 35 °C is unlikely for a normal marine precipitate. These cements, therefore, probably precipitated under shallow burial from waters that had been enriched in δ18O relative to contemporaneous seawater. For δ18O values from −10‰ to −7‰, an upper temperature limit of 100 °C can be extrapolated from the current reservoir temperature. The average δ18O value for these cements – −9‰ – indicates precipitation from water with δ18O = + 2‰, so suggesting a continuing trend towards increasing 18O-enrichment of the formation waters and increasing temperature on burial. This analysis therefore implies that the formation waters have evolved within a closed system without the introduction of external waters with isotopically different compositions. The δ18O of oil and water legs reach similarly negative values of −10.3‰ and −9.4‰, respectively. We infer that cementation has continued within both the water and oil legs to approximately the same burial depths and temperatures, with further cements formed selectively within the oil leg crest with less negative δ18O values, probably reflecting both the evolution of pore fluids and the structural uplift of the field. It is also possible that by the time the last cement zone precipitated in the water leg all available porosity was occluded such that the only space available for further cementation was within the crest.
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Fig. 7. Full transects of in-situ δ18O data given as numbered spot data points from oldest to youngest cements without reference to cement zone within syntaxial cements from, A) oil leg and B) water leg.
4.1. Role of oil charge, wettability and microporosity Wettability in carbonate reservoirs probably differs from that in siliciclastic fields, with carbonates predicted to be generally only weakly oil-wet (Barclay and Worden, 2000). The contact of positively charged calcite surfaces with the negative dipoles in oil causes a thin film of oil to form around pore interiors. The presence of oil even at low saturations should therefore preferentially adhere to grain surfaces but will leave the centres of pores water-filled. Under such circumstances, inhibition of new cement nucleation will begin at
much lower oil saturations in carbonate rocks than in water-wet siliciclastic reservoirs, but the continued growth of existing cements beyond the surficial oil film may not be precluded. Growing macrocements require a source of ions (i.e. Ca2+ and CO2− 3 ) and open transport paths for these to reach precipitation sites. Differences in cementation across reservoir structures may therefore be a consequence of the reduction in solute and water availability as well as the selective loss of permeability from crestal pore systems due to the shut-down of pores through the introduction of oil. Although it is considered that the majority of carbonate reservoirs contain oil-wet
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Table 2 In-situ δ18O ion microprobe data and position of oil inclusions. A, oil leg, B, water leg. Zone
Zone colour
Zone luminescence
Oil inclusions
Transect 1
A 1 2 3 4 5 6 7
Black Orange Yellow Orange Brown Orange Yellow
Dull Moderate Bright Moderate Dull Moderate Moderate
0 0 0 0 0 0 0
−1.2
8
Red
Moderate
6
9
Orange
Moderate
4
10
Yellow
Moderate
2
11 12
Orange Red-brown
Moderate Dull
0 2
Zone
Transect 2
Transect 3
Transect 4
Zone average (δ18O) −1.2
−4.7 −4.1 −4.1 −3.8
−6.3 −8.4 −8.7 −9.6 −9.1 −10.3 −7.4 −7.5
−6 −6.4 −8.2 −8.8
−7.8
−4.4 −4.4 −5.5 −4.4 −5.9 −6
−4.7 −4.1 4.1 −3.8 −4.4 −5 −7
−9.2
−7.9 −7.8 −7.9
−10.3 −7.7
Zone colour
Zone luminescence
Transect 1 (δ18O)
Transect 2 (δ18O)
Transect 3 (δ18O)
Transect 4 (δ18O)
Zone average (δ18O)
B 1
Black
Dull
−7.8
−7.4
−3.6
−6.6
2 3
Brown Brown
Moderate Dull
No data −8.2
−7.2 −7.6 −6 −6.5 No data −9.9 −5.1
No data
No data
No data −7.7
4
Orange
Moderate
−7.3
−9.2 −8.4
−7 −5.6
−7.5
5 6
Black Brown
Dull Dull
−9.3
−9.3
7
Brown
Dull
−9.2
−9.9 −9.9 −9.2
−9.1
macropore systems, micropore systems can remain water-wet due to high entry capillary pressures which typically produce high irreducible water saturations (Heasley et al., 2000). Whereas water-saturated micropores may be ineffective for the advective mass transfer of solutes, in the burial diagenetic environment where calcite is sourced mainly by pressure dissolution they may provide a pathway for the diffusion of solutes even where macropores are partially oil-filled. Heasley et al. (2000) show that within an oolitic reservoir, the water leg possesses a microporosity-dominated system due to the occlusion of macroporosity by burial cements, whereas in the oil leg a dual porosity system is retained in the oil leg reflecting limited macropore cementation. SEM imaging shows that the oil leg presents the best developed microrhombic fabrics with open microporosity (Fig. 4B). The incorporation of small crystals within larger ones and common larger microspar crystals within the compact anhedral fabrics often found in the water leg indicates a second generation of micrite cementation (Fig. 4D). This implies that the microporosity was preferentially reduced (or not further enhanced) within the water leg via micropore-fill cementation or syntaxial growth, as suggested by Moshier (1989). The δ18OVPDB of water- and oil leg micrite occupy distinct fields, where the average water leg value is −7.4‰, compared to −6.2‰ from the oil leg. This suggests continued cement precipitation at greater burial temperatures and depths within the water leg. Sources for burial calcite, provided by chemical dissolution sites, are suggested by the presence of intense stylolitization leading to porosity– permeability degradation (Harms and Choquette, 1965). Reservoir quality in Abu Dhabi ‘Thamama’ fields degrades from the crest to flank due to preferential stylolitization within the water leg and inhibition
−9.1 −9.6 −9.2
of more pervasive chemical compaction due to the early introduction of oil (Oswald et al., 1995; Grotsch et al., 1998). Compact anhedral textures as well as near total meso- and macropore occlusion by cements may therefore reflect abundant sources of solutes due to chemical compaction with accompanying solution-transfer cementation.
4.2. The dynamics of cementation There are major differences in cement volume across the reservoir structure, but accurate quantification of these differences is problematic. The greatest volume of cements is present in the water leg where 99% of the interparticle pore space is occluded; in the field crest interparticle pore space remains 95% open. As a result of the vagaries of thin section orientation oblique to cement growth direction and the variability of zone thickness within single cements, measured zone width may not reflect true cement thicknesses. Zone thickness cannot therefore be used as a measure of relative growth rates to compare cement zone volumes between the two legs. However, the final zone within the water leg with a mean δ18O value of −9.4 commonly occludes all remaining pore spaces (see Figs. 4C and 8A). Oil leg cements are relatively sparse but crystals can reach relatively large sizes (Fig. 4A), whereas water leg cements show abundant pore-filling cements of generally similar size. Considerably different volumes of cement have been precipitated in the two legs, with some suggestion that cement volume was highest in the final zone of the water leg.
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Fig. 8. Relative zone distribution and average in situ δ18O values for successive numbered zones within syntaxial cements from, A) water leg, and B) oil leg. Shaded zones indicate the absence of data; vertical bars show the data range for each zone. Lower part presents diagrammatic illustration of the distribution and differing relative thickness of cement zones.
During oil charge in carbonate rocks, a change in porewater movement from one dominated by macro- and mesoporosity to a solely water-wet micropore system will increase the tortuosity of fluid flow so reducing permeability and limiting the diffusional supply of carbonate. Solutes will take longer to reach potential sites of precipitation that are themselves further reduced by the increasing oil saturation in the larger pores. Cementation slows progressively and cement zones become thinner and coated with oil. Ultimately, cementation in these areas within the crest ceases leaving most interparticle pores open and cement free. By contrast in the water leg, the increasing volume of solutes provided by burial dissolution and moved by diffusion through micropores, promotes precipitation of the thickest cement zones so eventually occluding most remaining macro- and mesoporosity at the deepest point of burial.
Acknowledgments ADNOC and ZADCO managements and Schlumberger Cambridge Research are thanked for permission to publish this paper. Discussions with Ewart Edwards, Mohamed Braik Al Amri, Donatella Astratti and Olaf Schoenicke and technical support from Ali Ajjawi and his team of assistants at the Mussafah core facility were greatly appreciated. Colin Braithwaite and an anonymous reviewer improved the manuscript, and Mike Hall, Nicola Cayzer, Jonathan Naden and John Craven (NERC Ion Microprobe Facility) are thanked for technical support and
expertise. We acknowledge the support from the Scottish Funding Council for ECOSSE which is a part of the Edinburgh Research Partnership in Engineering and Mathematics (ERPem).
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Contents lists available at ScienceDirect
Sedimentary Geology j o u r n a l h o m e p a g e : w w w. e l s ev i e r. c o m / l o c a t e / s e d g e o
Dynamics of cementation in response to oil charge: Evidence from a Cretaceous carbonate field, U.A.E. P.A. Cox a,b,⁎, R.A. Wood a,b, J.A.D. Dickson c, H.B. Al Rougha d, H. Shebl d, P.W.M. Corbett b,e a
School of GeoSciences, University of Edinburgh, Kings Buildings, West Mains Road, Edinburgh, EH9 3JW. UK Edinburgh Collaborative of Subsurface Science and Engineering, UK Department of Earth Sciences, University of Cambridge, Downing Street, Cambridge, CB2 3EQ, UK d ZADCO, Abu Dhabi, United Arab Emirates e Institute of Petroleum Engineering, Heriot-Watt University, Riccarton Campus, Edinburgh, EH14 4AS, UK b c
a r t i c l e
i n f o
Article history: Received 1 December 2009 Received in revised form 28 April 2010 Accepted 29 April 2010 Available online 17 May 2010 Editor: B. Jones Keywords: Carbonate Diagenesis Calcite cements Oil charge Abu Dhabi Oxygen isotopes Microporosity
a b s t r a c t Oil charge is thought to inhibit the growth of cements within subsurface pore systems. We explore this phenomenon in a giant Cretaceous carbonate field from U.A.E., where the oil-filled crest porosity ranges from 10 to 50% and permeability from 0.08 to 830 mD but coeval water leg porosity is reduced to 10 to 23% and permeability to 0.1 to 4 mD. Only 5% of primary interparticle pores (N 30 μm diameter) in the crest are fully cemented, compared to 99% of pores in the water leg. Syntaxial calcite burial cements (N 10 μm diameter) in the oil leg show 12 cathodoluminescence zones with oil inclusions (n = 27) occurring in four of the five final zones. Mean in-situ ion microprobe δ18OVPDB data from the oil leg cements range from −1.2‰ in the oldest zone decreasing to −10.3‰ in zone 11, returning to −7.7‰ in the final zone. The oldest distinguishable cement zone in the water leg shows highly variable δ18O from −3.6‰ to −9.3‰ with a mean of −7.3‰, and with subsequent zones decreasing to a mean value of −9.4‰ for the youngest cement zone. Decreasing δ18O values are interpreted as indicating increasing temperature reflecting burial and the evolution of pore water composition: broadly similar trends in the oil and water legs suggest precipitation under the same general conditions. Unlike the oil leg cements, the final zone in the water leg occludes nearly all remaining pore space. The δ18OVPDB of bulk micrite from the water leg shows an average of −7.4‰ (n = 9) compared to −6.2‰ (n = 10) from the oil leg, suggesting the precipitation of further micrite cement at greater burial depths. We infer that burial cementation slowed in the presence of oil due to a reduction of potential nucleation sites as well as porewater and solute movement within weakly oil-wet pores, whereas continued flow and solute movement through all pores including the micropores (b 10 μm diameter) enabled extensive cementation in the water leg. © 2010 Elsevier B.V. All rights reserved.
1. Introduction Pore space in sedimentary rocks is known to decrease regularly with increasing burial depth but subsurface oil reservoirs are a notable exception to this pattern (Robinson and Gluyas, 1992; Emery et al., 1993). Oil reservoirs have greater porosity than their depth would indicate because they contain less cement than the surrounding rocks. When oil fills pores in sediments, water is partially displaced, and, as water is the medium for diagenetic reactions, cementation is inhibited or retarded (Worden et al., 1998; Heasley et al., 2000). Cementation and oil migration are thought to occur synchronously (Gluyas et al., 1993), but the oil-filling of reservoirs is a gradual
⁎ Corresponding author. School of GeoSciences, University of Edinburgh, Kings Buildings, West Mains Road, Edinburgh, EH9 3JW. UK. Tel.: +44 131 6506014; fax: +44 668 3184. E-mail address: [email protected] (P.A. Cox). 0037-0738/$ – see front matter © 2010 Elsevier B.V. All rights reserved. doi:10.1016/j.sedgeo.2010.04.016
process where pores in the crest are filled first (Marchand et al., 2001). Cement growth will therefore cease or slow initially in the crest and continue down the structure until the final oil/water contact is reached. Below the oil/water contact cementation can continue as long as conditions are right for precipitation in the water-saturated pores and space exists into which cement can grow. In both quartzcemented sandstone reservoirs (Walderhaug, 1990; Bjørkum et al., 1993; Emery et al., 1993) and calcite-cemented carbonate reservoirs (Neilson et al., 1996, 1998), cements within the oil leg contain inclusions of oil, indicating that they grew in pores that contained both water and oil. The retardation of quartz cement growth by the presence of oil has been modelled by Walderhaug (1994, 1996) and applied by Marchand et al. (2001, 2002) to North Sea fields that took N 15 Ma to fill with oil. The notion that cement growth and oil charge occur synchronously over millions of years during burial means that the conditions under which the cements grow are likely to change. Temperature will rise and formation waters evolve through reactions with the rocks
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during burial and with the passage of time. These changes should be reflected in the chemistry of the cement. The elemental chemistry of calcite is affected by many factors and is difficult to interpret (Richter et al., 2003) whereas the control of stable isotope composition is better understood. Calcite precipitated during burial will experience rising temperature with increasing depth, leading to progressively lower δ18OVPDB values. The δ18O evolution of formation waters is variable but commonly becomes greater due to calcite dissolution/re-precipitation reactions (Lawrence, 1988). Although these effects may cancel one another out, many analyzed late calcites show decreasing δ18OVPDB values related to increasing temperature during burial (Hudson, 1977). Carbonate rocks were collected from the Lower Cretaceous (late Hauterivian–late Barremian: 124–120 Ma) Kharaib Formation of the ‘Thamama’ Group, from a giant anticlinal oil field, offshore U.A.E. (Fig. 1A). The ‘Thamama’ Group is an informal title and encompasses the uppermost part of the Sahtan Supersynthem, the entire Kahmah Supersynthem, and the lowermost portion of the Wasi'a Supersynthem (Granier et al., 2003). The ‘Thamama’ Group contains the Habshan, Lekhwair, and Kharaib Formations, followed by the Hawar Member and finally the Shu'aiba Formation (Fig. 2). All these units were defined by subsurface data correlated throughout the southeastern Arabian Gulf, and are bounded by unconformities (Granier, 2000). They are often, but not always, bounded by transgressive surfaces that often coincide with sequence boundaries (Granier et al., 2003). The Kharaib Formation was deposited in a distal carbonate ramp setting and consists of a series of stacked reservoirs that follow 4th order high frequency sequences (Alsharhan et al., 1991). The Kharaib Formation lithology consists of mudstones–packstones–rudstones with dominant interparticle and microporosity. Lithologies are concentrated in the orbitilinid foraminiferan Palorbitolina lenticularis, the rudist Glossomyphorus costatus and various dasycladacean algae. The formation shows minimal laterally facies variation across the
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Fig. 2. Early–Middle Cretaceous stratigraphy of the ‘Thamama’ Group in U.A.E. (modified from Immenhauser et al., 2004).
entire offshore field and therefore between the water and oil legs within the field crest and flanks. The lowermost ∼ 2–3 m of the Lower Kharaib Formation is muddy, containing only echinoid fragments and Palorbitolina lenticularis. The Kharaib Formation was uplifted at 92 Ma (Sharland et al., 2001) as the Semail Ophiolite obducted onto the north western Arabian plate margin creating a series of low-angle domes trending northwest to south east (Fig. 1B). This tectonism activated movement of the Precambrian Ara salt layers below that further amplified these structures (Al-Barwani and Mclay, 2008). The field is faulted and fractured (Tamura et al., 2004; Edwards et al., 2006; Edwards, 2006). The main source of oil was the Shu'aiba basinal facies that is thought to have reached maturity during the late Cretaceous (Murris, 1980; Oswald et al., 1995; Milner, 1998) around or shortly after the onset of uplift and the start of trap formation (Gumati, 1993). The main phase of oil charge within the Kharaib Formation has been constrained to the late Eocene (Taher, 1997). Stylolites are common in the Kharaib Formation, and are parallel to bedding indicating a dominant vertical lithostatic stress. Welldeveloped stylolite levels show lower porosity and permeability due to enhanced chemical compaction with accompanying solutiontransfer cementation. Stylolites formed preferentially in the water leg (Oswald et al., 1995), but are also present in the oil leg reservoir facies and ubiquitous in muddy, dense facies in the lower section of reservoir cycles where alumino-silicate minerals probably catalysed pressure dissolution (Ehrenberg, 2003). Stylolitization is thought to have commenced after 600 m of burial at temperatures of approximately 65.6 °C (Oswald et al., 1995). Predictions as to the retardation of cementation and therefore retention of high porosity due to oil charge have been applied to calcite cement growth in Cretaceous reservoirs from Abu Dhabi (Kirkham et al., 1996; Neilson et al., 1998). Here we use δ18O data derived from in-situ ion microprobe measurements to explore the dynamic relationship between cement growth and oil emplacement. 2. Samples and methods
Fig. 1. A) Map showing the major ‘Thamama’ Group oil fields of U.A.E. (modified from Granier et al., 2003); B) the tectonic setting after 92 Ma, involving the Semail Ophiolite obduction and doming of Precambrian salts causing antiformal structures which now host many offshore and onshore oil fields surrounding Abu Dhabi (modified from Sharland et al., 2001).
All samples are rudist-orbitolinid packstones and rudstones collected from the same reservoir horizon from one cored well from the crest (oil leg) and one cored well from the western flank (water leg) of the field. The distance between the two wells is ∼20 km. The oil leg core measures ∼22 m and the water leg core 76 m. Ten 2″ by 3″ thin sections were analyzed from each well. Oil leg samples are at a current burial depth ∼220 m above the water leg samples. Calcite cements precipitated from both marine and meteoric waters are found in these rocks but only macrocements (N10 μm diameter) that crystallized from formation waters during burial are considered here. These macrocements occur in every
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sample and volumetrically dominated cementation. The relative cementation of primary interparticle pores N30 μm diameter was quantified by point-counting from blue epoxy-impregnated standard thin sections. Porosity and permeability data of the oil and water leg were measured commercially via mercury-injection from adjacent petrophysical plugs. A Leitz Metallux Leica 3 microscope, with a 100 W Hg HBO 103 W/ 2 bulb and a blue filter creating UV light with a waveband of 440– 490 nm was used to locate oil inclusions. All counted inclusions were assessed to be primary and contained a non-luminescent portion reflecting the presence of a vapour bubble. Inclusions close to fractures or cleavage planes were discounted as these may have been emplaced at any period during burial and so provide no information about oil charge relative to cementation. Powders of sample size 0.03–0.2 mg were extracted for isotope analysis from thin sections using a tungsten steel needle under a Leica 240 microscope. Areas of micrite lacking visible bioclasts or other grains were targeted. Powders were dissolved at 25 °C with 100% phosphoric acid followed by conventional mass spectrometry using a Thermo Electron Delta + Advantage. Results are reported as deviations from VPDB standard (‰) and precision was measured at a level better than 0.1‰ for δ13C and δ18O. Small rock chips were broken from core samples for SEM examination. Chips were cleaned in an ultrasonic tank, attached to aluminum stubs, gold-coated, and imaged using a Phillips XL30CP SEM in secondary electron mode. A 20Kv, 6 μm diameter electron
beam was used to image at 120× magnification and reduced to 4 μm in diameter at magnifications above 1950×. Syntaxial cements growing upon echinoid fragments were selected as these contain both the earliest cement zones and final zones abutting against pore space indicating preservation of the final, youngest cement growth. A Catholuminescence Cold cathode CITL 8200 MK3A was used to identify cement zones separated by differing luminescence (Mason and Mariano, 1990; Habermann et al., 1996, 1998). This formed the basis for establishing cement stratigraphies in the water and oil legs (Braithwaite, 1993). Three rock chips from each well were analysed from the Lower Kharaib Formation. Samples were gold-coated and placed within the Cameca 1270 Ion Microprobe to gain in-situ δ18O measurements for individual cement zones. A 10–15 µm diameter Cs ion beam was used to ablate 10–15 µm diameter spots from the sample. The internal precision for each spot ranges between 0.009 and 0.015 (% Standard Error). The external precision was estimated to be 0.4‰ as determined by consecutive analysis of a UWC (University of Wisconsin Calcite) standard that was assessed to be homogenous. All analyses were standardized against the UWC which was performed before each analysis within a separate holder. This decreased the accuracy of the method, but relative variations are believed to be precise to 0.4‰ (external precision of the UWC). For each syntaxial overgrowth a single transect was completed from the oldest, innermost cement adjacent to the echinoderm
Fig. 3. Porosity and permeability plot for the oil- and water leg within a single reservoir horizon of the Kharaib Formation, ‘Thamama’ Group, U.A.E. photomicrographs of A) the oil leg, showing relatively high porosity and permeability with retention of interconnected macropores and mesopores, and B) the water leg with near complete macropore and mesopore occlusions by cementation. Scale bar = 1 mm.
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Fig. 4. Secondary electron images of A, B, oil leg, and C, D, water leg. A) Open mesopores with burial macrocements. B) Euhedral microrohombic fabric with microporosity. C) Occluded mesopores, and D) Compact anhedral fabric with limited microporosity. A,C, Scale bar = 20 μm, B,D, Scale bar = 10 μm.
fragment to the youngest outermost cement abutting an open pore. This allowed δ18O values and trends through the macrocements to be compared regardless of zone colour and luminescence characteristics. Eight transects were performed across eight syntaxial cements: four syntaxial cements were analysed from each thin section, using one thin section each from the oil and water legs. 3. Results Oil crest sample porosity ranges from 10 to 50%, and permeability from 0.08 to 830 mD (Fig. 3). By contrast, water leg samples occupy a distinct field of lower porosity and permeability values of 10 to 23%, and 0.1–4 mD, respectively. Of a total of 247 primary interparticle pores N30 μm in the oil leg, only 13 were fully occluded by cement (5%). Of 865 interparticle pores in the water leg, 861 were fully cemented (99%). The oil leg retains many open macropores (N30 µm
in diameter) and mesopores (30–10 µm in diameter) in open communication leading to relatively high porosity and permeability (Figs. 3A and 4A). By contrast, water leg cements occlude nearly all macro- and mesopores pores (Figs. 3B and 4C). SEM imaging shows that micrite is represented by equant crystals and in the oil leg these form either compact anhedral, or subhedral to euhedral microrhombic fabrics. Crystals are 2–5 μm in compact anhedral, and 3–12 μm in microrhombic fabrics. Microrhombic micrites present an open texture (Fig. 4B) with micropores (defined as pores b10 μm diameter, Cantrell and Hagerty, 1999). By contrast, no euhedral microrhombic fabrics are found in the water leg, and the incorporation of smaller crystals within larger ones and the presence of isolated larger crystals indicate a second generation of microspar growth with limited microporosity (Fig. 4D). Cathodoluminescence revealed 12 zones in the oil leg and 7 zones in the water leg syntaxial cements (Fig. 5). The final, youngest zone
Fig. 5. Cathodoluminescence images of syntaxial cements (C), nucleating on echinoderm fragments (E) within, A) water leg, and B) oil leg. Note the differences in cement zone thicknesses, and how the final zone in the water leg sample occludes all remaining pore spaces. The black/blue areas on both images reflect open pores. Scale bar = 0.5 mm.
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Table 1 δ18O and δ13C data for bulk micrite. Water leg
Oil leg
δ13C
δ18O
δ13C
δ18O
2.643 2.824 2.978 3.152 3.089 3.27 2.789 3.201 3.283
−7.318 −7.932 −7.51 −7.267 −7.717 −7.489 −7.421 −7.414 −6.075
3.362 2.897 2.948 2.963 3.152 2.906 3.123 3.247 3.312 3.405
−5.522 −5.522 −5.938 −6.905 −6.64 −6.965 −6.677 −6.676 −6.403 −4.714
present in the water leg zone commonly occludes most remaining pore space within the surrounding matrix (Fig. 5A). A total of 27 oil inclusions were found in 4 syntaxial cements within the oil leg samples, in zones 8, 9, 10 and 12 (Table 2A). Oil inclusions measure between 1 and 5 µm in diameter and fluoresce pale apple-green indicating moderate maturity. Table 1 and Fig. 6 present δ18O and δ13C data from bulk micrite samples from the oil and water legs. The δ18OVPDB of bulk micrite from the water leg shows an average of −7.4‰ (n = 9) compared to −6.2‰ (n = 10) from the oil leg. Ion Microprobe in-situ δ18O data for each transect are shown in Fig. 7. Transects do not sample every cathodoluminescence zone, but include either the oldest or youngest zones. Data are presented in Table 2 according to zone, and the mean value for each zone with variance is presented in Fig. 8. δ18O data obtained from syntaxial cements range from −10.3‰ to −1.2‰. Most transects in both water and oil legs show a broad trend of decreasing δ18O from the oldest to youngest cements. Within the oil leg, some zones present a large range in values commonly showing clear trends of progressive negativity with decreasing age within a single zone; other zones show little variability. The early stages of the water leg zones show considerable variability in values. This may be due in part to the fact that many are less than 10 µm thick and cannot be adequately sampled individually with a 10–15 µm diameter ion beam. The entire range of δ18O values (∼ −10‰ to ∼ −1‰) was not found in any single pore or sample and complete sequences are deduced from several samples. In the oil leg, the earliest cement zone shows a mean value of −1.2‰, and following zones show a steady decrease
Fig. 6. Scatter plot of δ13C/δ18O for bulk micrite samples from water and oil legs. The δ18OVPDB of bulk micrite from the water leg shows an average of −7.4‰, compared to −6.2‰ from the oil leg.
down to −10.3‰ in zone 11. The final cement zone shows a return to a less negative δ18O value of −7.7‰. The oldest cement zone in the water leg shows highly variable δ18O, from −3.6‰ to −9.3‰ (n = 7), with a mean value of −7.3‰. Subsequent zones show consistently negative values decreasing to a value of −9.4‰ for the youngest cement zone. 4. Cementation and burial Several authors have suggested that oil may progressively displace porewater and retard cementation (e.g. Heasley et al., 2000; Neilson et al., 1996, 1998). Here, the number of oil inclusions is highest in zone 8 of the oil leg cements (mean δ18O value of −5‰) but decreases towards the youngest zone. This confirms that the main oil charge was followed by further cement growth within presumably partially oilwet pore systems. The correspondence of increasingly negative in-situ δ18O values with decreasing age within a single CL zone and disparities between adjacent sequences indicates that zones with the same luminescence characteristics may not necessarily have been precipitated within either stable or indeed similar conditions. Colour zonation cannot be used to correlate between the oil and water legs or as proof of time equivalence. The absence of more positive values in the early zones of the water leg zones may be an artefact and reflects the difficulty of sampling individual zones b10 μm in diameter. The variation in δ18O values from proximal to distal growth increments of cement crystals (Fig. 7) indicates that conditions changed during precipitation. This is most simply explained as due to rising temperature as a result of progressive burial. The δ18O values are consistent with mineralogical stabilisation of marine fluids under deep burial conditions. δ18O values of calcite precipitated at equilibrium are controlled by temperature and the δ18O composition of the water that can be expressed in the following equation (Kim and O'Neil, 1997): 3 −1 1000 InαðcalcitewaterÞ = 18:03 10 T –32:42 δ18O values of −7‰ to −1‰ using estimates of temperature of 20 °C for seawater and 50 °C for shallow burial waters indicates that the δ18O composition of the water may have varied between −6‰ and +5‰ (SMOW). The average value for cements with these δ18O values indicates precipitation from water with δ18O = O‰. This is high for a Lower Cretaceous greenhouse ocean. A water temperature of 35 °C is unlikely for a normal marine precipitate. These cements, therefore, probably precipitated under shallow burial from waters that had been enriched in δ18O relative to contemporaneous seawater. For δ18O values from −10‰ to −7‰, an upper temperature limit of 100 °C can be extrapolated from the current reservoir temperature. The average δ18O value for these cements – −9‰ – indicates precipitation from water with δ18O = + 2‰, so suggesting a continuing trend towards increasing 18O-enrichment of the formation waters and increasing temperature on burial. This analysis therefore implies that the formation waters have evolved within a closed system without the introduction of external waters with isotopically different compositions. The δ18O of oil and water legs reach similarly negative values of −10.3‰ and −9.4‰, respectively. We infer that cementation has continued within both the water and oil legs to approximately the same burial depths and temperatures, with further cements formed selectively within the oil leg crest with less negative δ18O values, probably reflecting both the evolution of pore fluids and the structural uplift of the field. It is also possible that by the time the last cement zone precipitated in the water leg all available porosity was occluded such that the only space available for further cementation was within the crest.
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Fig. 7. Full transects of in-situ δ18O data given as numbered spot data points from oldest to youngest cements without reference to cement zone within syntaxial cements from, A) oil leg and B) water leg.
4.1. Role of oil charge, wettability and microporosity Wettability in carbonate reservoirs probably differs from that in siliciclastic fields, with carbonates predicted to be generally only weakly oil-wet (Barclay and Worden, 2000). The contact of positively charged calcite surfaces with the negative dipoles in oil causes a thin film of oil to form around pore interiors. The presence of oil even at low saturations should therefore preferentially adhere to grain surfaces but will leave the centres of pores water-filled. Under such circumstances, inhibition of new cement nucleation will begin at
much lower oil saturations in carbonate rocks than in water-wet siliciclastic reservoirs, but the continued growth of existing cements beyond the surficial oil film may not be precluded. Growing macrocements require a source of ions (i.e. Ca2+ and CO2− 3 ) and open transport paths for these to reach precipitation sites. Differences in cementation across reservoir structures may therefore be a consequence of the reduction in solute and water availability as well as the selective loss of permeability from crestal pore systems due to the shut-down of pores through the introduction of oil. Although it is considered that the majority of carbonate reservoirs contain oil-wet
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Table 2 In-situ δ18O ion microprobe data and position of oil inclusions. A, oil leg, B, water leg. Zone
Zone colour
Zone luminescence
Oil inclusions
Transect 1
A 1 2 3 4 5 6 7
Black Orange Yellow Orange Brown Orange Yellow
Dull Moderate Bright Moderate Dull Moderate Moderate
0 0 0 0 0 0 0
−1.2
8
Red
Moderate
6
9
Orange
Moderate
4
10
Yellow
Moderate
2
11 12
Orange Red-brown
Moderate Dull
0 2
Zone
Transect 2
Transect 3
Transect 4
Zone average (δ18O) −1.2
−4.7 −4.1 −4.1 −3.8
−6.3 −8.4 −8.7 −9.6 −9.1 −10.3 −7.4 −7.5
−6 −6.4 −8.2 −8.8
−7.8
−4.4 −4.4 −5.5 −4.4 −5.9 −6
−4.7 −4.1 4.1 −3.8 −4.4 −5 −7
−9.2
−7.9 −7.8 −7.9
−10.3 −7.7
Zone colour
Zone luminescence
Transect 1 (δ18O)
Transect 2 (δ18O)
Transect 3 (δ18O)
Transect 4 (δ18O)
Zone average (δ18O)
B 1
Black
Dull
−7.8
−7.4
−3.6
−6.6
2 3
Brown Brown
Moderate Dull
No data −8.2
−7.2 −7.6 −6 −6.5 No data −9.9 −5.1
No data
No data
No data −7.7
4
Orange
Moderate
−7.3
−9.2 −8.4
−7 −5.6
−7.5
5 6
Black Brown
Dull Dull
−9.3
−9.3
7
Brown
Dull
−9.2
−9.9 −9.9 −9.2
−9.1
macropore systems, micropore systems can remain water-wet due to high entry capillary pressures which typically produce high irreducible water saturations (Heasley et al., 2000). Whereas water-saturated micropores may be ineffective for the advective mass transfer of solutes, in the burial diagenetic environment where calcite is sourced mainly by pressure dissolution they may provide a pathway for the diffusion of solutes even where macropores are partially oil-filled. Heasley et al. (2000) show that within an oolitic reservoir, the water leg possesses a microporosity-dominated system due to the occlusion of macroporosity by burial cements, whereas in the oil leg a dual porosity system is retained in the oil leg reflecting limited macropore cementation. SEM imaging shows that the oil leg presents the best developed microrhombic fabrics with open microporosity (Fig. 4B). The incorporation of small crystals within larger ones and common larger microspar crystals within the compact anhedral fabrics often found in the water leg indicates a second generation of micrite cementation (Fig. 4D). This implies that the microporosity was preferentially reduced (or not further enhanced) within the water leg via micropore-fill cementation or syntaxial growth, as suggested by Moshier (1989). The δ18OVPDB of water- and oil leg micrite occupy distinct fields, where the average water leg value is −7.4‰, compared to −6.2‰ from the oil leg. This suggests continued cement precipitation at greater burial temperatures and depths within the water leg. Sources for burial calcite, provided by chemical dissolution sites, are suggested by the presence of intense stylolitization leading to porosity– permeability degradation (Harms and Choquette, 1965). Reservoir quality in Abu Dhabi ‘Thamama’ fields degrades from the crest to flank due to preferential stylolitization within the water leg and inhibition
−9.1 −9.6 −9.2
of more pervasive chemical compaction due to the early introduction of oil (Oswald et al., 1995; Grotsch et al., 1998). Compact anhedral textures as well as near total meso- and macropore occlusion by cements may therefore reflect abundant sources of solutes due to chemical compaction with accompanying solution-transfer cementation.
4.2. The dynamics of cementation There are major differences in cement volume across the reservoir structure, but accurate quantification of these differences is problematic. The greatest volume of cements is present in the water leg where 99% of the interparticle pore space is occluded; in the field crest interparticle pore space remains 95% open. As a result of the vagaries of thin section orientation oblique to cement growth direction and the variability of zone thickness within single cements, measured zone width may not reflect true cement thicknesses. Zone thickness cannot therefore be used as a measure of relative growth rates to compare cement zone volumes between the two legs. However, the final zone within the water leg with a mean δ18O value of −9.4 commonly occludes all remaining pore spaces (see Figs. 4C and 8A). Oil leg cements are relatively sparse but crystals can reach relatively large sizes (Fig. 4A), whereas water leg cements show abundant pore-filling cements of generally similar size. Considerably different volumes of cement have been precipitated in the two legs, with some suggestion that cement volume was highest in the final zone of the water leg.
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Fig. 8. Relative zone distribution and average in situ δ18O values for successive numbered zones within syntaxial cements from, A) water leg, and B) oil leg. Shaded zones indicate the absence of data; vertical bars show the data range for each zone. Lower part presents diagrammatic illustration of the distribution and differing relative thickness of cement zones.
During oil charge in carbonate rocks, a change in porewater movement from one dominated by macro- and mesoporosity to a solely water-wet micropore system will increase the tortuosity of fluid flow so reducing permeability and limiting the diffusional supply of carbonate. Solutes will take longer to reach potential sites of precipitation that are themselves further reduced by the increasing oil saturation in the larger pores. Cementation slows progressively and cement zones become thinner and coated with oil. Ultimately, cementation in these areas within the crest ceases leaving most interparticle pores open and cement free. By contrast in the water leg, the increasing volume of solutes provided by burial dissolution and moved by diffusion through micropores, promotes precipitation of the thickest cement zones so eventually occluding most remaining macro- and mesoporosity at the deepest point of burial.
Acknowledgments ADNOC and ZADCO managements and Schlumberger Cambridge Research are thanked for permission to publish this paper. Discussions with Ewart Edwards, Mohamed Braik Al Amri, Donatella Astratti and Olaf Schoenicke and technical support from Ali Ajjawi and his team of assistants at the Mussafah core facility were greatly appreciated. Colin Braithwaite and an anonymous reviewer improved the manuscript, and Mike Hall, Nicola Cayzer, Jonathan Naden and John Craven (NERC Ion Microprobe Facility) are thanked for technical support and
expertise. We acknowledge the support from the Scottish Funding Council for ECOSSE which is a part of the Edinburgh Research Partnership in Engineering and Mathematics (ERPem).
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