Impact of oil emplacement on diagenesis in Cretaceous oil sands

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Jun 2, 2017 - The only cement observed in these oil sands are the viscous ... some of the studied Cretaceous oil sands after the sandstones had undergone ...
Impact of oil emplacement on diagenesis in Cretaceous oil sands

Timothy Bata Department of Applied Geology Abubakar Tafawa Balewa University Bauchi, Nigeria

John Parnell

Abstract Seventeen thin sections of Cretaceous oil sands from the Neuquén Basin (Argentina), Sergipe-Alagoas Basin (Brazil), Western Canadian Sedimentary Basin (Canada), Junggar Basin (China), Lower Saxony Basin (Germany), Kangerlussuaq Basin (Greenland), Arabian Basin (Kuwait), Chad Basin (Nigeria), Dahomey Basin (Nigeria), Western Moray Firth Basin (UK), Wessex Basin (UK) and Utah (USA) were examined using the scanning electron microscope (SEM) to improve our understanding on how oil emplacement impairs the progress of diagenesis. Our results show that diagenetic processes affecting sandstones prior to oil emplacement include burial/compaction, silica/calcite cementation, calcite replacement of detrital grains/cements as well as the development of silica overgrowth. Most diagenetic processes were inferred to cease upon oil emplacement into the pores of the sandstones, however, diagenetic processes such as the alteration of detrital grains/cements and precipitation of authigenic minerals/metallic compounds were observed to occur after oil emplacement into the pores of the sandstones. Oil was emplaced in some of the studied Cretaceous oil sands at a relatively early stage when the sandstones were not compacted or cemented. Such Cretaceous oil sands were observed to have had anomalously high porosities of above 38% prior to oil emplacement. The only cement observed in these oil sands are the viscous heavy oils (bitumens) associated with them. Upon extraction of these heavy oils, the oil sands collapse into unconsolidated sands. Occurrence of these bitumen supported Cretaceous sands implies availability of migrating oils while some of the Cretaceous sands were depositing in various basins. Oil emplacement occurred in some of the studied Cretaceous oil sands after the sandstones had undergone some diagenetic processes which did not destroy all their pore spaces. Such Cretaceous oil sands were observed to have had moderate to high porosities of 10%–30% prior to oil emplacement, with some of these sandstones showing evidence of silica overgrowth. Emplacement of oil into the pores of such sandstones is believed to have stopped further development of the silica overgrowth that would have led to the total loss of porosity in these Cretaceous reservoir sands. In some of the studied Cretaceous oil sands, oil emplacement occurred when the sands had experienced a long history of diagenetic events leading to almost total loss of porosity. Common diagenetic features observed in such Cretaceous oil sands include sutured quartz grain-grain contacts and quartz overgrowth.

School of Geosciences University of Aberdeen United Kingdom AB24 3UE

Nuhu K. Samaila Department of Applied Geology Abubakar Tafawa Balewa University Bauchi, Nigeria

John Still School of Geosciences University of Aberdeen United Kingdom AB24 3UE

Résumé Afin de mieux comprendre dans quelle mesure la mise en place du pétrole affecte la progression de la diagenèse, on a examiné, à l’aide du microscope à balayage électronique (MBE), dix-sept lames minces de sables bitumineux du Crétacé provenant des endroits suivants : bassin de Neuquén (Argentine), bassin de Sergipe-Alagoas (Brésil), bassin sédimentaire occidental canadien (Canada), bassin de Junggar (Chine), bassin de Basse-Saxe inférieur (Allemagne), bassin de Kangerlussuaq (Groenland), bassin de la mer d’Oman (Koweït), bassin du lac Tchad (Nigéria), bassin du Dahomey (Nigéria), bassin occidental de Moray Firth (R.-U.), bassin de Wessex (R.-U.) et Utah (É.-U.). Nos résultats indiquent que les processus diagénétiques qui affectent le grès avant la mise en place du pétrole incluent l’enfouissement, la compaction, la cimentation

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silico-calcitique, le remplacement calcitique de grains et ciments détritiques, de même que l’accroissement secondaire de silice. On supposait que la plupart des processus diagénétiques devait cesser avec la mise en place du pétrole dans les pores du grès; après observations, cependant, les processus diagénétiques, en l’occurrence l’altération des grains et ciments détritiques, d’une part, et la précipitation de composés minéraux et métalliques authigènes, d’autre part, se produisaient après l’entrée du pétrole dans les pores du grès. Durant la période où le grès n’était ni compacté ni cimenté, le pétrole s’est mis en place dans certains sables bitumineux du Crétacé à un stade relativement précoce. Avant la mise en place du pétrole, de tels sables bitumineux du Crétacé avaient une porosité anomale supérieure à 38%. Le seul ciment observé dans ces sables pétrolifères était sous la forme de pétrole lourd visqueux (bitume) associé à celui-ci. Au cours de l’extraction de ces pétroles lourds, le sable bitumineux s’est effondré en sable non consolidé. L’existence de ces sables du Crétacé supportés par le bitume suppose la disponibilité du pétrole qui migre, tandis qu’une partie des sables du Crétacé se déposait ailleurs dans divers bassins. La mise en place du pétrole s’est produite dans certains sables bitumineux du Crétacé étudiés après que le grès ait été soumis à des processus diagénétiques lesquels n’ont pas détruit tous les interstices. De tels sables du

Crétacé avaient des porosités allant de modérées à élevées soit de 10% à30 % avant la mise en place du pétrole, et certains des grès affichaient des indices d’accroissement secondaire de silice. On croit que la mise en place de pétrole dans les pores de ces grès aurait stoppé l’accroissement secondaire de silice, ce qui aurait mené à la perte totale de porosité dans les gisements pétrolifères du Crétacé. Dans certains des sables bitumineux du Crétacé étudiés, la mise en place du pétrole est arrivée lorsque les sables ont été soumis à un long épisode de diagenèse conduisant à une quasi-perte totale de porosité. Les caractéristiques diagénétiques communes remarquées dans les sables du Crétacé incluent des sutures de points de contact entre les grains et un accroissement secondaire de quartz. Michel Ory

Introduction Oil sand refers to highly viscous oil-containing reservoir sands (e.g. Fig. 1) which are too viscous to flow to a wellbore and, as such, are uneconomic to produce without technological intervention. Surface mining operations are commonly used to separate the heavy oil (bitumen) from the sand, mostly by

Figure 1. Examples of field photograph showing outcrops of oil sands. a) Outcrop of the Wealden Group, at the Mupe Bay locality, Wessex Basin UK. Note oil-stained matrix sandstone and the relatively darker oil-stained clast sandstones. b) Outcrop of the Wealden Group, at the West Lulworth cove locality, Wessex Basin UK. c) Outcrop of the Wealden Group, at the East Lulworth cove locality, Wessex Basin UK. d) Another outcrop of the Wealden Group, at the West Lulworth cove locality, Wessex Basin UK. Page 328

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hot-water separation processes. World resources of bitumen and heavy oil are estimated to be 5.6 trillion bbl, with more than 80% occurring in Canada, Venezuela, and the United States (Hein, 2006). The heavy oils associated with oil sands are commonly interpreted as degraded conventional oils (Head et al., 2003; Bata et al., 2015, 2016; Bata, 2016). The two most important processes that act on light oil to produce heavy oil are biodegradation (hydrocarbon oxidation process involving the microbial metabolism of various classes of compounds which alters the oil’s fluid properties and economic value) and water washing (the removal of the more water-soluble components of petroleum, especially low molecular weight aromatic hydrocarbons such as benzene, toluene, ethylbenzene and xylenes) (Palmer, 1993). In general, water washing and biodegradation are accepted by geochemists as a ubiquitous phenomenon wherever crude oil is in contact with oxygen and bacteria-carrying meteoric water (Palmer, 1993; Krumholz et al., 1997; Bata et al., 2015, 2016; Bata, 2016). The detrital composition of oil sand has a great influence on its reservoir quality since it conditions the pathways of both physical and chemical diagenesis (Bloch and Helmond, 1995). Intra-formation variations in detrital composition are known to cause significant heterogeneity in sandstone reservoir quality. Quartz, feldspars and, in a lesser proportion, clay minerals and rock fragments, are the main framework constituents of oil sands. Opaque minerals, micas (biotite and muscovite), and heavy minerals occur as accessory constituents, but nonetheless had an effect on the diagenetic reactions that occurred during burial (Deschamps et al., 2012). The arrangements of the sand, water and bitumen in oil sand is believed to be one whereby each particle of the sand is water wet, and a film of bitumen envelops the water-wetted grains. The balance of the void volume is filled with bitumen, connate water, or gas; fine material, such as clay, also occurs within the water envelope (Speight, 2012). In general, the reservoir quality of sandstone is controlled by factors such as depositional porosity and permeability. These are, in turn, strongly influenced by sorting, grain size, grain morphology and the sand/mud matrix ratio in the depositional environment. Other factors that influence sandstone reservoir quality include the degree of mechanical and chemical compaction, the amount and type of pore-filling cement, and the geothermal gradient. Paragenetic relationships between hydrocarbons and inorganic minerals in oil reservoirs can provide information on the relative timing of hydrocarbon migration as well as the migration of other fluids (Parnell, 1994). Early diagenesis includes all the processes that occur at, or near, the sediment depositional surface, where the geochemistry of the interstitial waters is controlled mainly by the depositional environment. Early diagenesis can also be defined in terms of temperature, geothermal gradient and depth, where the upper temperature limit is 30%)

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10

Tugulu Group

Junggar Basin China

48.6%

11

Mannville Group

Western Canada Sedimentary Basin

54%

12

Mesaverde Formation

Uinta Basin, USA

38.8%

T. Bata, J. Parnell, N.K. Samaila and J. Still

porosity of the studied oil sands at the time of oil emplacement. Summary of these porosity values are presented in Table 2. Some of these estimated porosity values are comparable to porosity values obtained from other alternative methods. For example, average porosity estimate for the Burgan Formation reported in this study is 23%, which is comparable to the average porosity value of 21.2% reported by Mahbaz et al. (2011). Similarly, the average porosity estimate for the Afowo Formation presented in this study is 17.8%, which is comparable to the average porosity value of 19.5% reported by Oladunjoye et al. (2014). The porosity of the sandstone petroleum reservoir at the time of oil emplacement is important because it is a measure of the space available in the reservoir sand at the time of oil emplacement. How much porosity was available at the time of oil emplacement depends on grain size, sorting, roundness and the diagenetic processes that acted on the sandstone prior to oil emplacement. Studied Cretaceous oil sands with negligible to poor porosities at the time of oil emplacement include the Watkins Fjord Formation (1.6%), the Bentheim Sandstone (3.1%), the Serraria Formation (4%), the Huitrin Formation (5.5%) and the Bima Formation (8.2%) (Table 2). These studied Cretaceous oil sands from Kangerlussuaq Basin (Greenland), Lower Saxony Basin (Germany), Sergipe-Alagoas Basin (Brazil), Neuquén Basin (Argentina) and Chad Basin (Nigeria) respectively are believed to have been deeply buried, hot, and perhaps with much water flux prior to oil emplacement. This explains the low porosities and extensive diagenetic features observed in them. Observed diagenetic processes with negative impact on porosity in the studied Cretaceous oil sands include calcite cementation and development of silica overgrowths (e.g. Figs. 2, 3a and 7a). Oil emplacement in pores of these oil sands is believed to have stopped further development of the silica overgrowth which would have led to the total loss of porosity in the sandstones.

Sutured quartz grain-grain contacts occurred in some of those Cretaceous oil sands with negligible to poor porosity at the time of oil emplacement (e.g. Fig. 10). Some of these oil sands show evidence of heavy oils occurring in fractures (e.g. Fig. 2), The occurrence of vein porosity could imply that the oils, which were emplaced with great pressure, filled available pore spaces and fractured the sandstones to make room for more oil. Oil production from oil sands with negligible porosity is difficult due to the poor inter-connected porosity (permeability). An example of the paragenetic sequence of oil sands that had negligible to poor porosity at the time of oil emplacement is presented in Figure 11. Studied Cretaceous oil sands with moderate to very good porosities at the time of oil emplacement include the Wealden Group (12%) and the Afowo Formation (17.8%), the Valhall Formation Captain 1 sand (18.8%), Valhall Formation Captain 2 sand (19.2%) and the Burgan Formation (23%) (Table 2). Oil emplacement occurred in these oil sands after the sandstones had undergone some diagenetic processes which did not destroy the pore spaces. Some of these oil sands also show evidence of silica overgrowth (e.g. Figs 3b, 4a and 7b). Emplacement of oil in pores of these sandstones is believed to have stopped further development of the silica overgrowth. An example of the paragenetic sequence of such oil sand is presented in Figure 12. A common diagenetic feature observed in the studied oil sands that had moderate to very good porosities at the time of oil emplacement was the alteration of detrital grains which was believed to have occurred after oil emplacement. Oil production from these oil sands with moderate to very good porosities is possible. Typical examples are the oils presently being produced from the Burgan Sand in the Burgan Field of Kuwait and the Valhall Formation (Captain Sand) of the Captain Field in the North Sea UK.

Figure 10. a) Backscattered SEM photomicrograph of a section from the Watkins Fjord Formation showing detrital minerals including quartz (Q) and K-feldspars (Kf ). Observed cements include calcite (black arrow), K-feldspar (kfc), silica (Qc) silica overgrowth (Qo), and iron oxide (feo). Note sutured contacts of grains (white arrow) and bitumen (Hc) occurring in secondary pore spaces created by dissolution of feldspar. b) Backscattered SEM photomicrograph of a section from the Bentheim Sandstone showing detrital quartz (Q), calcite (Ca), clay minerals (Cl) and pyrite (Py). Clay minerals are observed to partly replace some detrital grains and cement. Also note calcite partly replacing some detrital grains and cements. Some secondary porosities (red arrow) were created by dissolution of some detrital grains. Black arrows show sutured grain contact. Diagenesis of Cretaceous Oil Sands

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Figure 11. Paragenetic sequence for the studied sample of the Bentheim Sandstone constructed from petrographic evidence.

Figure 12. Paragenetic sequence for the Afowo Formation constructed from petrographic evidence.

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Studied Cretaceous oil sands with abnormal porosities above 30% include the Mannville Group (54%), the Tugulu Group (48.6%) and the Mesaverde Formation (38%) (Table 2; Fig. 10). These studied Cretaceous oil sands with abnormal porosities from the Western Canadian Sedimentary Basin, Junggar Basin (China) and Utah (USA) respectively have not been deeply buried, nor were they particularly hot prior to oil emplacement. An example of the paragenetic sequence of such oil sands is presented in Figure 13. The only cement observed in these sands is the viscous heavy oils. When these viscous heavy oils are completely extracted, the sands collapse into unconsolidated sand as illustrated with the Mannville Group in Figure 14. Heavy oils associated with the studied

Mannville Group in Western Canadian Sedimentary Basin are believed to have been sourced from petroleum source rocks that are Devonian to Early Cretaceous in age. Estimated time of oil generation is 240 to 0 Ma (Deschamps et al., 2012; Bata, 2016). This implies a syn-depositional reservoir charge concept in which there was availability of migrating oils in the Western Canadian Sedimentary Basin when the Cretaceous Mannville Group was depositing. Similarly, heavy oils associated with the studied Tugulu Group in the Junggar Basin, China are believed to have been sourced from Permian rocks. Estimated time of oil generation is 260 to 100 Ma (Parnell et al., 1994; Bata, 2016). This also suggests the availability of migrating oils in the Junggar Basin when the Cretaceous Tugulu Group was depositing.

Figure 13. Paragenetic sequence for the Mannville Group constructed from petrographic evidence.

Figure 14. Photomicrograph of the Mannville Group showing quartz: a) the Mannville Group with constituent minerals cemented by bitumen; and b) unconsolidated sand grains of the Mannville Group after oil extraction.

Diagenesis of Cretaceous Oil Sands

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Conclusions Oils occurring in reservoir rocks can generally be considered as being paragenetically late because the pores and fractures hosting the oils could have had some history of fluid evolution before hydrocarbon emplacement. Geological factor controlling the widespread occurrence of Cretaceous oil sands can be attributed to the prevalence of Cretaceous reservoir sands with good reservoir capabilities. Availability of viable petroleum source rocks at the time of deposition, or shortly after the deposition of Cretaceous sands is another important factor that contributed to the widespread occurrence of Cretaceous oil sands. Diagenetic processes that act on reservoir sands prior to oil emplacement have been observed to strongly influence sand reservoir properties. Specifically, this study demonstrates the following: 1) Oil was emplaced in the studied Mannville Group, Tugulu Group and Mesaverde Formation at a relatively early stage when the sandstones were not compacted and not cemented. This syn-depositional reservoir charge concept suggests availability of migrating oils in the respective sedimentary basins when the sands were depositing. The only cement observed in these studied Cretaceous oil sands with anomalous high porosities is the heavy oils associated with the oil sands. Complete extraction of the heavy oils is possible after which the sands collapses into unconsolidated sands. 2) Oil emplacement occurred in the studied Wealden Group, Afowo Formation, Valhall Formation and Burgan Formation after the sandstones had undergone some diagenetic processes which did not destroy all their pore spaces. These sandstones show evidence of silica overgrowth. Oil emplacement in these sandstones is believed to have stopped further development of the silica overgrowth that would have led to total loss of porosity in these reservoir sands. 3) Studied Serraria Formation, Bentheim Sandstone, Huitrin Formation Watkins Fjord Formation and Bima Formation are believed to have been deeply buried, hot, and perhaps with much water flux, prior to oil emplacement. This explains the very low porosities and extensive diagenetic features observed in them. Conversely, studied Mannville Group, Tugulu Group and Mesaverde Formation have not been deeply buried, nor were they particularly hot prior to oil emplacement. This explains the anomalous high porosities and insignificant diagenetic features observed in them. 4) Authigenic metallic minerals/compounds observed to be associated with some of the studied oil sands include uraninite, copper sulfide, vanadium and titanium oxide. The inferred origin of some of these authigenic metals is the interaction of metal-bearing fluids derived from surface waters flowing off hinterland basement rocks and hydrocarbons migrating from source rocks in the deeper parts of a basin. Some of these authigenic metals are inherited from the petroleum sources. 5) Petrographic evidences suggesting the occurrence of authigenic silica crystals within viscous heavy oils were obtained in this study. An interpretation for the occurrence of these authigenic silica crystals is that they precipitated from silica-saturated ground waters that interacted with the viscous oils. There is also evidence to suggest that some Page 340

of these authigenic silica crystals are products of feldspar alteration.

Acknowledgments Timothy Bata is thankful to the Petroleum Technology Development Fund of Nigeria for sponsoring his PhD research at the University of Aberdeen, and the management of Abubakar Tafawa Balewa University Bauchi, Nigeria, for permitting him to proceed on study leave. We acknowledge the British Geological Survey for providing core samples of the Captain Sand used in this study. We also acknowledge the help and support received from the Nigerian Geological Survey Agency Akure during the field work in Nigeria. We are grateful to Michael Webb, Ian Hutcheon and a third anonymous reviewer for their critical review of this manuscript. We are also grateful to the handling Associate Editor, Jen Russel-Houston.

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Manuscript received: 2016/09/20 Date accepted: 2017/03/22 Associate Editor: Jen Russel-Houston

T. Bata, J. Parnell, N.K. Samaila and J. Still