Joyce E. Neilson

The relationship between petroleum emplacement and carbonate reservoir quality: examples from Abu Dhabi and the Amu Darya Basin

Abstract The relative importance of petroleum emplacement in inhibiting diagenetic processes and preserving porosity and permeability in Lower Cretaceous, Thamama Group (Kharaib Formation) carbonate reservoirs of Abu Dhabi, UAE, and in Callovian-Kimmeridgian carbonate reservoirs of the Amu Darya Basin in Uzbekistan and Turkmenistan, has been evaluated by combining geologic, petrophysical and geochemical data. When petroleum emplacement is synchronous with and prior to significant burial cementation in carbonates, primary petroleum inclusions are trapped in the cements. The process appears to be characterised by steep intra-field porosity-depth trends within a more gradual regional decline in porosity with depth. This has profound implications for the prediction of porosity in carbonate reservoirs. Reservoir quality is better in grainstones and packstones compared to adjacent wackestones and lime mudstones in the Kharaib Formation because of preserved macroporosity (intergranular, vuggy, mouldic); the pore system in the finer units is dominated by micropores. These features indicate a primary textural control on porosity and permeability. Within the grainstones and packstones, macroporosity is variably filled by late equant sparry calcite cements. Porosity and permeability variations in grainstones and packstones at a reservoir scale are therefore controlled by the variation in amount of equant sparry calcite cement. This in turn depends on the timing of the precipitation of this cement relative to petroleum emplacement, as shown by fluid inclusion data. Where petroleum emplacement has occurred relatively early, at migration foci, prior to significant burial cementation by equant sparry calcite, reservoir quality is preserved. Where it has occurred after significant burial cementation, reservoir quality has been destroyed. In the Amu Darya sequences, primary macroporosity is commonly preserved down to depths of 11,000 ft (3.5 km) with differences in the porosity and permeability characteristics of grainstones being controlled by variations in the amount of early, probably freshwater, cement and the extent of associated dissolution. Small volumes of burial cements do occur, but they do not contain petroleum inclusions. Consequently, there is no firm evidence that petroleum emplacement has inhibited diagenesis in this area. This part of the study has shown that it is not always possible to obtain conclusive evidence from the diagenesis to pin down the processes responsible for the preservation of reservoir quality and that petroleum filling may not always be the primary cause. The relationships documented here show that the ‘race for space’ between diagenetic waters and petroleum is a major control on reservoir quality in the Thamama Group carbonate reservoirs, but is not so important for the Jurassic carbonates in the Amu Darya basin.

Advances in carbonate exploration and reservoir analysis

Abstract The development of innovative techniques and concepts, and the emergence of new plays in carbonate rocks are creating a resurgence of oil and gas discoveries worldwide. The maturity of a basin and the application of exploration concepts have a fundamental influence on exploration strategies. Exploration success often occurs in underexplored basins by applying existing established geological concepts. This approach is commonly undertaken when new basins ‘open up’ owing to previous political upheavals. The strategy of using new techniques in a proven mature area is particularly appropriate when dealing with unconventional resources (heavy oil, bitumen, stranded gas), while the application of new play concepts (such as lacustrine carbonates) to new areas (i.e. ultra-deep South Atlantic basins) epitomizes frontier exploration. Many low-matrix-porosity hydrocarbon reservoirs are productive because permeability is controlled by fractures and faults. Understanding basic fracture properties is critical in reducing geological risk and therefore reducing well costs and increasing well recovery. The advent of resource plays in carbonate rocks, and the long-standing recognition of naturally fractured carbonate reservoirs means that new fracture and fault analysis and prediction techniques and concepts are essential. A key area of progress has been integration of stratigraphic, structural, geomechanical and diagenetic analysis to populate reservoir models accurately. Dramatic increases in computing and digital imaging capabilities are being harnessed to improve spatial analysis and spatial statistics in reservoirs and ultimately improve 3D geocellular models.

The impact of carbonate texture on the quantification of total porosity by image analysis

Image analysis is widely used to quantify porosity because, in addition to porosity, it can provide quantitative pore system information, such as pore sizes and shapes. Despite its wide use, no standard image analysis workflow exists. When employing image analysis, a workflow must be developed and evaluated to understand the methodological pitfalls and assumptions to enable accurate quantification of total porosity. This study presents an image analysis workflow that is used to quantify total porosity in a range of carbonate lithofacies. This study uses stitched BSE-SEM photomicrographs to construct greyscale pore system images, which are systematically thresholded to produce binary images composed of a pore phase and a rock phase. The ratio of the area of the pore phase to the total area of the pore system image defines the total porosity. Image analysis total porosity is compared with total porosity quantified by standard porosimetry techniques (He-porosimetry and mercury injection capillary pressure (MICP) porosimetry) to understand the systematics of the workflow. The impact of carbonate textures on image analysis porosity quantification is also assessed.A comparison between image analysis, He-porosimetry and MICP total porosity indicates that the image analysis workflow used in this study can accurately quantify or underestimate total porosity depending on the lithofacies textures and pore systems. The porosity of wackestone lithofacies tends to be significantly underestimated (i.e. greater than 10%) by image analysis, whereas packstone, grainstone, rudstone and floatstone lithofacies tend to be accurately estimated or slightly underestimated (i.e. 5% or less) by image analysis. The underestimation of image analysis porosity in the wackestone lithofacies is correlated to the quantity of matrix pore types and is thought to be caused by incomplete imaging of microporosity and by unrepresentative fields of view. Image analysis porosity, which is calculated from 2D areas, is comparable with 3D porosity volumes in lithofacies that lack or are weakly microporous; in such lithofacies, image analysis is assumed to be accurately measuring other 2D parameters, including pore sizes and shapes. Image analysis accurately quantifies or underestimates porosity (?) in carbonates.The estimation of ? depends on the lithofacies texture and the pore system.? is significantly underestimated in wackestones.This underestimation is caused by micro-? and unrepresentative fields of view.? is accurately quantified or slightly underestimated in lithofacies lacking micro-?.

An investigation of porosity–velocity relationships in faulted carbonates using outcrop analogues

Abstract Porosity and permeability are notoriously difficult to predict in carbonates, especially prior to drilling when there is a lack of direct petrophysical data. The aim of this paper is to document the initial results of an integrated outcrop and laboratory study designed to investigate the relationships between pore systems and acoustic velocities in faulted Oligo-Miocene carbonates on the Mediterranean islands of Malta and Gozo. Depositional facies is shown to have a significant effect, with velocities in grain-dominated carbonates up to 1000 m s−1 higher than those in micrite-dominated carbonates. Based on outcrop structural data, the fault zones can be separated into three architectural components: a fault core; an intensely damaged zone; and a weakly damaged zone, with the last passing into undamaged protolith. Our data suggest that only the fault core component can be identified using porosity–velocity data, with P-wave velocity (Vp) values of 5000–6500 m s−1 at helium porosities of less than 5%. Our study is novel in that the prediction of elastic properties and acoustic velocities across fault zones is anticipated by linking laboratory-scale measurements with seismic-scale predictions through quantitative rock physics modelling.

Summary of the AAPG–SPE–SEG Hedberg Research Conference on “Fundamental Controls on Flow in Carbonates”

A joint AAPG–Society of Petroleum Engineers–Society of Exploration Geophysicists Hedberg Research Conference was held in Saint-Cyr sur Mer, France, on July 8 to 13, 2012, to review current research and explore future research directions related to improved production from carbonate reservoirs. Eighty-seven scientists from academia and industry (split roughly equally) attended for five days. A primary objective for the conference was to explore novel connections among different disciplines (primarily within geoscience and reservoir engineering) as a way to define new research opportunities. Research areas represented included carbonate sedimentology and stratigraphy, structural geology, geomechanics, hydrology, reactive transport modeling, seismic imaging (including four-dimensional seismic, tomography, and seismic forward modeling), geologic modeling and forward modeling of geologic processes, petrophysics, statistical methods, numerical methods for simulation, reservoir engineering, pore-scale processes, in-situ flow experiments (e.g., x-ray computed tomography), visualization, and methods for data interaction. The conference was organized into four thematic sessions on the first two days (fundamentals, measurement and detection of flow on laboratory to field scales, uncertainty and prediction, and novel modeling and simulation techniques); a field trip on the third day was preceded by a dedicated poster session that introduced the geology of the area, whereas the ice breaker featured guest lectures on innovation and complex adaptive leadership, as well as a panel discussion. Given the challenge of cross-disciplinary communication, delegates were encouraged to adopt a beginners mind, challenging the status quo and exploring basic questions that the establishment might have overlooked. Stepping back and slowing down to promote effective conversations among different disciplines was emphasized upfront. Several delegates noted that technical jargon was a significant barrier to novel thinking in the way that it impeded effective communication among disciplines during the meeting. Cross-disciplinary interactions were encouraged by several further mechanisms, representing a shift from more common Hedberg Conference formats. Overall, the …

Fracture patterns in carbonate fault zones and their influence on petrophysical properties

Maltese field examples of variable carbonate lithofacies in fault displacements ranging from ~20cm up to 100m are used to examine how different carbonates deform, and to understand evolution of the fault zone architecture and ultimately their petrophysical signatures. The evolution of fault zone architecture in time and space, and the associated changes in deformation mechanisms, exert an important control over the sealing potential of faults. It has been suggested that faults in carbonates could form seals after as little as ~20 m displacement, especially when juxtaposed next to a different formation. However, as seen in the Maltese examples, the complete opposite may occur. An intense zone of deformation is formed, which enhances both the porosity and permeability on an outcrop scale. This also prevents the localisation of deformation onto one slip surface, stopping the formation of a continuous, impermeable fault core. Examination of how the rocks deform, through different deformation mechanisms, can potentially help unravel the relationship between fault zone architecture and petrophysical properties. It can also help to indicate the potential evolution of the petrophysics through understanding scaling of the damage zone relationships with displacement of different carbonate lithofacies.

Diagenetic and tectonic evolution of pore networks in carbonate normal fault zones and their effects on permeability

This study quantifies changes in carbonate fabrics and pore network characteristics in fault zones using field analogues with the ultimate aim of understanding fluid flow around carbonate hosted normal fault zones. The shallow water carbonate sequence in Malta, which is dissected by an array of normal faults of varying displacements, is the chosen field analogue. The study reveals a wide range in petrophysical properties on the core plug scale. Porosity ranges from less than 5 % to greater than 35 %, permeability varies by seven orders of magnitude from 0.001 mDs to 1000 mDs and ultrasonic p-wave velocity ranges between 2 and 6 km/s. The range in these petrophysical properties is in part due to primary depositional fabric. However, modifications of the primary fabric during subsequent diagenesis and deformation are important in shaping the petrophysical properties of the rock. Pore throat size and pore type are important characteristics of the pore network which control the permeability. The changes in the carbonate fabrics into fault zones results in pore throat size and pore type changes and hence modifies the permeability. Total porosity and rock fabric are important controls on the p-wave velocity and can allow for predictions of pore network characteristics.