Sandbody Connectivity Research Articles

Research on Combined Method of Sedimentary Facies under Multiple Conditional Constraints

When we were studying the oil field, this article described the morphology, scale, and connectivity of sand bodies by observing the combination of sedimentary facies in the oil field. At the same time, we also found that the sand body is related to the origin, distribution, physical properties, and Changes in heterogeneity, etc., these factors play a crucial guiding role in the development and adjustment of oil fields. However, in specific phase belt combinations, subjective influence factors are relatively large, and the phase belt maps of oilfields have certain limitations in the development adjustment process. In this paper, the sedimentary facies of the Sapu oil layer in the Harwin Oilfield are re-understood through various constraints such as regional sedimentary environment, well-seismic combined reservoir prediction results, and the matching relationship between fluids and structures on the plane. We make the combination of facies zones more reasonable. Accurate, providing a basis for adjustment of oilfield water injection development.

Petroleum Geological Analysis Based on Remote Sensing and laser scanning in Karamay Formation of Junggar Basin, China

This paper uses high-precision remote sensing and laser scanning to study petroleum geological analysis methods. The research area is Karamay Formation in Junggar Basin, China. Firstly, the outcrop lithologies are identified according to our clastic rock lithology identification pattern based on laser intensity, and the regional lithologies are identified based on high-precision remote sensing images. Furthermore, we analyze the horizontal and vertical distribution characteristics of the sandbodies. At last, we analyze the area sandbody connectivity and sandbody structure characteristics. These data can provide basic information for the analysis of underground reservoirs in Karamay Formation.

Factors controlling the reservoir accumulation of Triassic Chang 6 Member in Jiyuan-Wuqi area, Ordos Basin, NW China

Abstract In the Triassic Yanchang Formation, Jiyuan-Wuqi area, Ordos Basin, the Chang 6 reservoir is contacted to the Chang 7 high-quality source rock, but the oil pools are unevenly distributed, and complex in oil and water distribution. Through cores observation and fracture statistics, combined with comprehensive analyses of physical property, mercury injection, logging and geochemical data, and comparisons of the sandbodies scales, reservoir physical properties, argillaceous laminae and fractures between source and reservoir in the eastern and western oil-bearing areas and in the central water producing area, it is found that the hydrocarbon accumulation patterns are different in the eastern, central and western areas, and the characteristics of hydrocarbon migration under the background of double-provenance were sorted out. The study results show that the crude oil in the eastern area has different Pr/Ph and sterane distribution from that in the western area. The oil and gas primarily migrated vertically. The high-quality source rocks and favorable source-reservoir-cap combinations lay the foundation for large-scale oil and gas accumulations. Vertically, the oil and gas enrichment is controlled by the scale of sandbody and the difference of physical properties, while on the plane, it is controlled by the connectivity of sandbodies, the argillaceous laminae between source rock and reservoir, the reservoir physical property and the fractures. The sandbodies of oil-rich zones in the eastern and western areas have large thickness, low shale content, good physical properties, weak heterogeneity, few argillaceous laminae and abundant fractures, all of which are favorable for the vertical migration and accumulation of oil and gas. In contrast, in the middle area with converging provenances, the reservoirs, composed of thin sandbodies, features rapid variation in lithology and physical properties, strong heterogeneity, poor continuity of sandbodies, abundant argillaceous laminae between source rock and reservoir, and few fractures, makes it difficult for the oil and gas to migrate vertically, and results in low oil enrichment degree ultimately. For the exploration of continental multiple-provenance tight reservoirs, not only the good-property source rocks and reservoirs, but more importantly the source-reservoir contact relationship and the effect of fractures on the hydrocarbon migration and accumulation should be considered.

The connectivity of reservoir sand bodies in the Liaoxi sag, Bohai Bay basin: Insights from three-dimensional stratigraphic forward modeling

The distribution of sand bodies is complex in small half-graben rift basins influenced by differential tectonic subsidence. The characterization of reservoir sand bodies remains half quantitative because the depositional processes of the sand bodies are poorly understood and quantitatively investigated. Based on wells and seismic data, a three-dimensional stratigraphic forward modeling is conducted to quantitatively characterize the depositional evolution of reservoir stratigraphy and to analyze the connectivity of sand bodies as well as its controlling elements in Liaoxi Sag, Bohai Bay Basin. We integrate Controlling factors for sequence development including initial bathymetry of basement, subsidence, lake level change, sediment supply, and sediment transport Dionisos program to establish a 3D reservoir-sequence model for the middle part of the third member of Eocene Shahejie Formation. The model matches the wells data of the oilfield, such as lithologies, gamma ray, and resistivity, making it credible to further predict sandstone distribution. The sedimentary process of reservoir sand bodies appear four stages. In stage 1, two prototypes of delta-front sand bodies developed in the northwest. In stage 2, both the western delta-front sand bodies and eastern slope-fan sand bodies were widely developed. In stage 3, the delta-front sand bodies developed in large scale, whereas the slope fans were smaller. In stage 4, only a slope-fan sand body developed in the southeast, whereas lacustrine shale dominated in the rift basin.During the depositional evolution process, the western sand bodies were not connected to the eastern sand bodies. This disconnection is a function of source supply and sustained slope sinking caused by basin differential subsidence. We tested the interplay of tectonic subsidence and sediment supply through the stratigraphic modeling. Under the conditions of bilateral source supply, the limited number of sand sediments from western delta front could not be transported to the eastern structure high. Nevertheless, under assumptions of one source supply and strong water flow, the plentiful sand sediments could be carried onto the eastern structurally elevated position. Therefore basin differential subsidence and bilateral supply of source are the two controlling factors for the sand distribution in small half grabens. In addition, we found an interesting phenomenon that sand ratio in rifted basin center increases with subsidence decreasing. However, it will be a constant (upper limit) when subsidence declines to a threshold value. The threshold of “subsidence slope” (vertical subsidence divided by length of slope) varied with climate and sedimentary environment. In warm climate and delta environment, the threshold value is 2.3°.

Analysis of floodplain sedimentation, avulsion style and channelized fluvial sandbody distribution in an upper coastal plain reservoir: Middle Jurassic Ness Formation, Brent Field, UK North Sea

Abstract Numerical models and recent outcrop case studies of alluvial-to-coastal-plain strata suggest that autogenic avulsion can control the stacking density and architecture of channelized fluvial sandbodies. The application of these models to subsurface well data was tested by the analysis of upper coastal plain deposits of the late Bajocian Ness Formation in the Brent Field reservoir, UK North Sea. These coastal plain deposits accumulated during the progradation and retrogradation of the wave-dominated ‘Brent Delta’. Sedimentological facies analysis and palaeosol characterization in cores were used to interpret the styles of palaeochannel avulsion. These results were then compared with the dimensions and distributions of channelized fluvial sandbodies that had been quantified by spatial statistical tools (lacunarity, Besag's L function) applied to interpretative correlation panels between closely spaced wells. The results indicate that the distributions of channelized sandbodies may plausibly have been generated by avulsions and that they influence sandbody connectivity and pressure depletion patterns. Intervals of upper coastal plain strata with relatively wide sandbodies that display some clustering in their stratigraphic architecture are associated with a high proportion of avulsions by incision and annexation in core samples. Such intervals display relatively good vertical pressure communication and relatively slow, uniform pressure depletion.

Multiscale hyporheic exchange through strongly heterogeneous sediments

AbstractHeterogeneity in hydraulic conductivity (K) and channel morphology both control surface water‐groundwater exchange (hyporheic exchange), which influences stream ecosystem processes and biogeochemical cycles. Here we show that heterogeneity in K is the dominant control on exchange rates, residence times, and patterns in hyporheic zones with abrupt lithologic contrasts. We simulated hyporheic exchange in a representative low‐gradient stream with 300 different bimodal K fields composed of sand and silt. Simulations span five sets of sand‐silt ratios and two sets of low and high K contrasts (1 and 3 orders of magnitude). Heterogeneity can increase interfacial flux by an order of magnitude relative to homogeneous cases, drastically changes the shape of residence time distributions, and tends to decrease median residence times. The positioning of highly permeable sand bodies controls patterns of interfacial flux and flow paths. These results are remarkably different from previous studies of smooth, continuous K fields that indicate only moderate effects on hyporheic exchange. Our results also show that hyporheic residence times are least predictable when sand body connectivity is low. As sand body connectivity increases, the expected residence time distribution (ensemble average for a given sand‐silt ratio) remains approximately constant, but the uncertainty around the expectation decreases. Including strong heterogeneity in hyporheic models is imperative for understanding hyporheic fluxes and solute transport. In streams with strongly heterogeneous sediments, characterizing lithologic structure is more critical for predicting hyporheic exchange metrics than characterizing channel morphology.

A comparative study of reservoir modeling techniques and their impact on predicted performance of fluvial-dominated deltaic reservoirs

Multiple techniques are available to construct three-dimensional reservoir models. This study uses comparative analysis to test the impact of applying four commonly used stochastic modeling techniques to capture geologic heterogeneity and fluid-flow behavior in fluvial-dominated deltaic reservoirs of complex facies architecture: (1) sequential indicator simulation; (2) object-based modeling; (3) multiple-point statistics (MPS); and (4) spectral component geologic modeling. A reference for comparison is provided by a high-resolution model of an outcrop analog that captures facies architecture at the scale of parasequences, delta lobes, and facies-association belts. A sparse, pseudosubsurface data set extracted from the reference model is used to condition models constructed using each stochastic reservoir modeling technique. Models constructed using all four algorithms fail to match the facies-association proportions of the reference model because they are conditioned to well data that sample a small, unrepresentative volume of the reservoir. Simulated sweep efficiency is determined by the degree to which the modeling algorithms reproduce two aspects of facies architecture that control sand-body connectivity: (1) the abundance, continuity, and orientation of channelized fluvial sand bodies; and (2) the lateral continuity of barriers to vertical flow associated with flooding surfaces. The MPS algorithm performs best in this regard. However, the static and dynamic performance of the models (as measured against facies-association proportions, facies architecture, and recovery factor of the reference model) is more dependent on the quality and quantity of conditioning data and on the interpreted geologic scenario(s) implicit in the models than on the choice of modeling technique.

Characterization of stratigraphic architecture and its impact on fluid flow in a fluvial-dominated deltaic reservoir analog: Upper Cretaceous Ferron Sandstone Member, Utah

Fluviodeltaic stratigraphic architecture and its impact on fluid flow have been characterized using a high-resolution, three-dimensional, reservoir-scale model of an outcrop analog from the Upper Cretaceous Ferron Sandstone Member of central Utah. The model contains two parasequence sets (delta complexes), each with five or six parasequences, separated by an interval of coastal plain strata. Each parasequence contains one or two laterally offset teardrop-shaped delta lobes that are 6 to 12 km (4–7 mi) long, 3 to 9 km (2–6 mi) wide, 5 to 29 m (16–95 ft) thick, and have aspect ratios (width/length) of 0.4 to 0.8. Delta lobes have a wide range of azimuthal orientations (120) around an overall east-northeastward progradation direction. In plan view, delta lobes in successive parasequences exhibit large (as much as 91) clockwise and counterclockwise rotations in progradation direction, which are attributed to autogenic lobe switching. In cross-sectional view, parasequence stacking is strongly progradational, but a small component of aggradation or downstepping between parasequences reflects relative sea level fluctuations. We use flow simulations to characterize the impact of this heterogeneity on production in terms of the sweep efficiency, which is controlled by (1) the continuity, orientation, and permeability of channel-fill sand bodies; (2) the vertical permeability of distal delta-front heteroliths; (3) the direction of sweep relative to the orientation of channel-fill and delta-lobe sand bodies; and (4) well spacing. Distributary channel-fill sand bodies terminate at the apex of genetically related delta lobes and provide limited sand body connectivity. In contrast, fluvial channel-fill sand bodies cut into, and connect, multiple delta-lobe sand bodies. Low, but non-zero, vertical permeability within distal delta-front heteroliths also provides connectivity between successive delta-lobe sand bodies.

Predicting the impact of sedimentological heterogeneity on gas–oil and water–oil displacements: fluvio-deltaic Pereriv Suite Reservoir, Azeri–Chirag–Gunashli Oilfield, South Caspian Basin

ABSTRACT The Pereriv Suite reservoir in the Azeri culmination of the ACG Oilfield is characterized by laterally continuous layers of variable net-to-gross (NTG) ratio deposited in a channel-dominated, fluvio-deltaic environment. The reservoir is being developed by down-dip water injection, with up-dip gas injection on the more steeply dipping central north flank. We use high-resolution models derived from outcrop analogue and subsurface data to demonstrate that four key sedimentological heterogeneities control recovery in both oil–water and gas–oil displacements: (1) local variations in NTG within low NTG ( 85%) layers; (3) sinuosity and (4) stacking pattern of channel-fill sandbodies in low NTG layers. The first three heterogeneities control sandbody connectivity; the fourth controls sweep efficiency in the connected sandbodies. Two further heterogeneities control recovery in gas–oil displacements in high NTG layers: (5) vertical-to-horizontal permeability ratio of channel-fill sandbodies and (6) mud clast lags at channel bases. Models which omit these small-scale features predict that sedimentological heterogeneity has little impact on water–oil or gas–oil displacements in high NTG layers, but fail to capture the effect of heterogeneity on the gravity stability of the gas–oil displacement, which significantly impacts on recovery.

Controls on the Architecture of a Triassic Sandy Fluvial System, Wolfville Formation, Fundy Basin, Nova Scotia, Canada: Implications for the Interpretation and Correlation of Ancient Fluvial Successions

Abstract Architectural-element analysis was developed to describe and reconstruct fluvial system stacking patterns and understand the controls on fluvial architecture. The architecture of braided fluvial systems at the scale of channel belts is still poorly understood, and upscaling from outcrop observations to basin-scale architecture remains partly speculative. Nonetheless, predictive sedimentary models are necessary to understand the connectivity of sand bodies from small scale (outcrop) to basin scale. This contribution presents a dataset from the Late Triassic sandy braided fluvial system of the Fundy Basin (Nova Scotia, Canada). We describe facies associations, architectural elements, and stacking patterns at different scales, and discuss the controls on fluvial architecture and upscaling issues. The studied section shows, at the base, multilateral stacked channel bodies with little preservation of fine-grained floodplain facies. It changes upwards into multistory stacked channel bodies that form channel-belt complexes intercalated with thicker floodplain deposits. Based on grain-size evolution, large-scale sequences encompass several channel-belt complexes. Controls on channel and channel-belt migration or avulsion are considered to be related to autocyclic processes. In contrast, large-scale vertical evolution and grain-size variations record allocyclic signals. In particular, gradual grain-size variations suggest a climatic control which influences the bedload transport capacity of the depositing fluvial system. Architectural evolution including an upward increase in the preservation of floodplain units is considered to be due to an increase in generation of accommodation space. We question the existing definition of the order of large-scale (sixth- to seventh- order) bounding surfaces recognized previously and highlight difficulties associated with reconstructing development of a regional fluvial system using these bounding surfaces.

Braided river and distribution patterns of sand bodies of Jurassic Badaowan formation in Block T13 of Junggar basin

In order to determine the planar and volume distribution of sand bodies of the Jurassic Badaowan formation in Block T13 of Junggar basin, we used analysis of field outcrop and 3D seismic data, which play an essential role in areas of sparse well coverage. We describe sedimentary facies characteristics, sand body planforms, width and connectivity patterns of sand bodies, and vertical associations and successions by acoustic impedance inversion technology and sedimentological theory. Results of our study show braided fluvial strata deposits in the Jurassic Badaowan formation. Each sand body is approximately lenticular in shape. The width of each sand body falls in the range 100∼800 m, with most between 200 and 400 m. The sand bodies vary in thickness from 4 to 13 m, with most below 9 m. The width/thickness ratios lie in the range 20∼55. The connectivity of braided fluvial channel sand bodies is controlled by changes of accommodation space. One fining-upward sedimentary cycle of base-level rise is recognized in Badaowan formation, representing an upward rise of base level. The connectivity of sand bodies was found to be greatest in the early stage of base-level rise, becoming progressively worse with increasing base-level rise.

The Key Geological Factors Influencing on Development of Low-Permeability Sandstone Reservoirs: A Case Study of the Taizhao Area in the Songliao Basin, China

As a typical low-permeability reservoir in the periphery of the Daqing oilfield, the Putaohua reservoir in the Taizhao area has a development characteristic similar to that of the low-permeability sandstone reservoirs in China. Through a synthetic analysis of its geology, logging and dynamic data, sandbody connectivity, small faults, tiny structures, fractures and present-day stress are the geological factors influencing the developmental effects. The connectivity of single sandbody and its anisotropy influence distribution of oil and water and inhomogenous fluid flow. The early water breakthrough in some oil wells was mostly caused by high permeability sandbobies. Sand bodies together with small faults and tiny structures influence the development effect of low-permeability reservoirs throuh impacting on fluid flow. Fractures are the main factor for high-water-cut oil-producing wells. Fractures developed in the paleotectonic stress field. The preservation and permeability of every assemblage of fractures are controlled by the present-day stress field, which also influences cracking and injection. There developed four assemblages of tectonic fractures of high dip angle in the Putaohua reservoir. Affected by the present-day stress field, the E-W fractures that have a good connectivity and permeability and big apertures, are the main seepage orientation. At present, the injection pressure has exceeded the unsealing pressure of E-W fractures. Therefore, water content appears early and goes up quickly, causing a serious water flood in the E-W array of oil wells. However, oil wells of other directions show a poor effect.

Comparison of interwell connectivity predictions using percolation, geometrical, and Monte Carlo models

Reservoir connectivity is often an important consideration for reservoir management. For example, connectivity controls waterflood sweep efficiency and it affects decisions concerning well placement and spacing. The uncertainty of sandbody distributions, however, can make interwell connectivity prediction extremely difficult. Percolation models are a useful tool to simulate sandbody connectivity behavior to estimate interwell connectivity. This study applies a percolation method to estimate interwell connectivity. Using results derived by Andrade, King, and others for fluid travel time between locations in a percolation model, we develop a method to estimate interwell connectivity. Four parameters are needed to use this approach: the net-to-gross ratio p sand, the typical sandbody size, reservoir length and well spacing. To evaluate this new percolation method, the results are compared to results from geometrical models, Monte Carlo, and reservoir simulation. These methods were applied to estimate interwell connectivity for three non-communicating stratigraphic intervals in Monument Butte oil field, Utah. The results suggest that the percolation method can estimate the probability of interwell connectivity reliably for thin intervals for any values of p sand, well spacing, and reservoir length. The geometrical model also performs well, but can only be applied in fields where the well spacing is less than one-half of the sandbody size. The proposed method requires that the reservoir interval for evaluation be sufficiently thin so that 2D percolation results can be applied. For thick intervals or heterogeneous sandbody distributions, the percolation method developed here is not suitable because it assumes thin layers. Future percolation research will be needed to adapt this new method to 3D cases.

Addressing uncertainty and remaining potential in a mature field. A case study from the Tertiary of Lake Maracaibo, Venezuela

Abstract The Urdaneta West Field is located on the western margin of Lake Maracaibo in northern Venezuela. Biodegraded oil (12–15° API) is reservoired in Tertiary sandstones and produced through a series of lateral wells. The productive sandstones of the Icotea and Misoa Formations are thin, calculated as 0.5–4.5 m (1.5–15 ft) vertical thickness, and of limited lateral extent. This heterogeneity, coupled with heavy oil, results in poor fluid communication and low recovery efficiency. During 2004, a full field review was undertaken to address future development. Despite production from the Icotea and Misoa Formations, subsurface uncertainty was identified as a major issue due to the clustered nature of field development, complex depositional and structural environments, and reservoir fluid characteristics. In order to rank and mitigate reservoir uncertainties, a series of static models were built. The first phase of static modelling used a simple structural framework and reservoir interval averages to generate minimum, mid- and maximum volume cases. Dynamic simulation of these identified two major areas of uncertainty impacting oil-in-place and productivity – net sandbody connectivity and hydrocarbon contact. Two further phases of static and dynamic modelling concentrated on evaluating the full range of these uncertainties within a detailed structural framework.

Connectivity of channelized reservoirs: a modelling approach

Connectivity represents one of the fundamental properties of a reservoir that directly affects recovery. If a portion of the reservoir is not connected to a well, it cannot be drained. Geobody or sandbody connectivity is defined as the percentage of the reservoir that is connected, and reservoir connectivity is defined as the percentage of the reservoir that is connected to wells. Previous studies have mostly considered mathematical, physical and engineering aspects of connectivity. In the current study, the stratigraphy of connectivity is characterized using simple, 3D geostatistical models. Based on these modelling studies, stratigraphic connectivity is good, usually greater than 90%, if the net: gross ratio, or sand fraction, is greater than about 30%. At net: gross values less than 30%, there is a rapid diminishment of connectivity as a function of net: gross. This behaviour between net: gross and connectivity defines a characteristic ‘S-curve’, in which the connectivity is high for net: gross values above 30%, then diminishes rapidly and approaches 0. Well configuration factors that can influence reservoir connectivity are well density, well orientation (vertical or horizontal; horizontal parallel to channels or perpendicular) and length of completion zones. Reservoir connectivity as a function of net: gross can be improved by several factors: presence of overbank sandy facies, deposition of channels in a channel belt, deposition of channels with high width/thickness ratios, and deposition of channels during variable floodplain aggradation rates. Connectivity can be reduced substantially in two-dimensional reservoirs, in map view or in cross-section, by volume support effects and by stratigraphic heterogeneities. It is well known that in two dimensions, the cascade zone for the ‘S-curve’ of net: gross plotted against connectivity occurs at about 60% net: gross. Generalizing this knowledge, any time that a reservoir can be regarded as ‘two-dimensional’, connectivity should follow the 2D ‘S-curve’. For channelized reservoirs in map view, this occurs with straight, parallel channels. This 2D effect can also occur in layered reservoirs, where thin channelized sheets are separated vertically by sealing mudstone horizons. Evidence of transitional 2D to 3D behaviour is presented in this study. As the gross rock volume of a reservoir is reduced (for example, by fault compartmentalization) relative to the size of the depositional element (for example, the channel body), there are fewer potential connecting pathways. Lack of support volume creates additional uncertainty in connectivity and may substantially reduce connectivity. Connectivity can also be reduced by continuous mudstone drapes along the base of channel surfaces, by mudstone beds that are continuous within channel deposits, or muddy inclined heterolithic stratification. Finally, connectivity can be reduced by ‘compensational’ stacking of channel deposits, in which channels avoid amalgamating with other channel deposits. Other factors have been studied to address impact on connectivity, including modelling program type, presence of shale-filled channels and nested hierarchical modelling. Most of the stratigraphic factors that affect reservoir connectivity can be addressed by careful geological studies of available core, well log and seismic data. Remaining uncertainty can be addressed by constructing 3D geological models.

Sequence stratigraphic-based analysis of reservoir connectivity: influence of sealing faults – a case study from a marginal marine depositional setting

This case study of the Sunrise and Troubadour fields (offshore northwest Australia) deals with the impact of sealing faults on reservoir connectivity via a sequence stratigraphic-based, 3D reservoir modelling approach. The marginal marine, wave- and fluvial-dominated reservoir succession was subdivided into sequence stratigraphic units. The connectivity of sandbodies in each parasequence was calculated, following a palinspastic restoration of the 3D models to a depositional datum (depositional connectivity). Once the top structure and fault architecture interpreted from seismic data were incorporated into the 3D models, sandbody connectivity was again calculated on the same stratigraphic basis, with the faults being considered sealing (structural connectivity). The impact on sandbody connectivity of additional, probabilistic, sub-seismic sealing faults was also analysed. The results indicate that the depositional architecture is the controlling factor on reservoir connectivity for low sealing fault densities. However, at a critical sealing fault density, the major control becomes the structural architecture. Using the approach detailed in this paper, relationships between sealing fault density and reservoir connectivity for different development well layout scenarios can be predicted as a basis for optimizing development well patterns.

Virtual outcrop models of petroleum reservoir analogues: a review of the current state-of-the-art

A subsurface reservoir model is a computer based representation of petrophysical parameters such a porosity, permeability, fluid saturation, etc. Given that direct measurement of these parameters is limited to a few wells it is necessary to extrapolate their distribution. As geology is a first order control on petrophysics, it follows that an understanding of facies and their distribution is central to predicting reservoir quality and architecture. The majority of reservoir modelling systems used for the subsurface are based on correlation of seismically-derived surfaces to define reservoir zones. Well data are then used to define further, sub-seismic scale horizons and determine the zone properties which are represented in grid cells. Understanding the distribution of both sub-seismic surfaces and potential heterogeneous geology between them remains a significant challenge. Furthermore as the typical grid cell size is c. 50-200 m2 it is challenging to incorporate small-scale heterogeneities. It is critical, therefore, to use realistic values for both key stratigraphic horizons and internal facies distributions. Depositional facies is a fundamental control on petrophysics. However, facies scale heterogeneities are not resolvable using current seismic methods, and well data provide little or no data on 3D geometries beyond the well bore. Studies of modern sedimentary events can give some indication of the link between depositional processes and facies distribution (e.g., Kenyon et al., 1995); however preserved depositional architecture is also strongly controlled by changes in accommodation through time (Jervey, 1988). Laboratory-based experiments (e.g., Kneller & Buckee, 2000) and process-based modelling (e.g. Aigner et al., 1989; Peakall et al., 2000) further illustrate the link between depositional mechanism and facies architecture. However, such models are typically on a scale that is far smaller than the typical field and are more applicable to upscaling studies (Nordhal et al., 2005; Ringrose et al., 2005). Outcrop studies have long been employed as a mechanism of studying analogues and understanding petroleum fields (Collinson, 1970; Glennie, 1970; Breed & Grow, 1979). Once the type of depositional system and the accommodation history of a hydrocarbon field are derived from subsurface data, appropriate outcrop analogue(s) can then be identified (e.g. Alexander, 1993). Suitable analogues are those that are geologically comparable to the system that is being studied and also have excellent 3D outcrop exposure over an area that is large enough to capture the scale of heterogeneity required (Clark & Pickering, 1996). Outcrop analogue studies are thus a key way of improving understanding of reservoir facies architecture, geometry, and facies distributions. Outcrop analogue studies have been undertaken both qualitatively and more recently quantitatively. Traditional quantitative studies (e.g., Dreyer et al., 1993; Chapin et al., 1994; Bryant & Flint, 1993; Clark & Pickering, 1996; Reynolds, 1999) have been focused on the collection of outcrop data to populate inter-well reservoir model areas by stochastic, object-based methods (Floris & Peersmann, 2002). However, it can be difficult to extract usable data from traditional outcrop studies, especially when it needs to be integrated with petroleum engineering databases or to be visualized in 3D. Furthermore, outcrops which represent a topographic cut through solid geology are 2D and while rare examples show multiple sections through the solid geology with different orientations, geological expertise is still required to fully understand and interpret the 3D nature of the bodies. Such work may also need geostatistical data manipulation to overcome outcrop orientation and size issues (Geehan & Underwood, 1993; Vissa & Chessa, 2000) but ideally the data should be reconstructed in 3D. Accurate 3D reconstruction is the only way that parameters such as channel sinuosity, connectivity, and continuity of target sandbodies in 3D may be defined. Such parameters are a key control on hydrocarbon production, including sweep efficiency (Pringle et al., 2004a; Larue & Friedmann, 2005). Software for representing geology in 3D is routinely used to model subsurface reservoirs. This paper will show how recent digital data capture technique advances aids the interpreting reservoir geologist by obtaining accurate and quantitative outcrop analogue datasets to aid and perhaps modify his reservoir model.

ModDRE: A program to model deepwater-reservoir elements using geomorphic and stratigraphic constraints

In deepwater-reservoir modeling, the proper representation of the spatial distribution of architectural elements is important to account for pore-volume distribution and the connectivity of reservoir sand bodies. This is especially critical for rock and fluid-volume estimates, reservoir-performance predictions, and development-well planning. A new integrated stochastic reservoir-modeling approach (ModDRE— Modeling Deepwater Reservoir Elements) accounts for geomorphic and stratigraphic controls to generate the deepwater-reservoir architecture. Information on stratal-package evolution and sediment provenance can be integrated into the reservoir-modeling process. A slope-area analytical approach is implemented to account for topographical constraints on channel and sheet-form reservoir architectures and their distribution. Inferred sediment–source statistics and architectural-element variability (from seismic, outcrop, and stratigraphic studies) associated with relative changes in sea level can also be used to constrain the deepwater-reservoir-element statistics. Based on these geomorphic and stratigraphic constraints, deepwater-reservoir elements (channels, lobes) are built into the model sequentially (in stratigraphic order). Integration of realistic geological and engineering attributes into deepwater-reservoir models is vital for optimal reservoir management. This approach is unique in that it is more directly constrained to geomorphic and stratigraphic parameters than traditional object- or surface-based techniques for stochastic deepwater-reservoir modeling.

Sequence stratigraphic-based analysis of reservoir connectivity: influence of depositional architecture – a case study from a marginal marine depositional setting

This case study of the Sunrise and Troubadour fields (offshore northwest Australia) concentrates on the impact of primary depositional architecture on reservoir connectivity via a sequence stratigraphic-based, 3D reservoir modelling approach. The marginal marine reservoir is composed of fluvial-dominated and wave-dominated depositional environments. The succession is divided into six sequences and 12 systems tracts. Each systems tract is subdivided into parasequences which form the basic building blocks of the 3D model. The connectivity of sandbodies within each parasequence, systems tract and sequence were calculated when the models were palinspastically restored to a depositional datum. The findings indicate that depositional connectivity trends within a sequence stratigraphic framework are predictable. Connectivity trends can be related directly to depositional and stratigraphic trends and to position in the sequence stratigraphic hierarchy. Therefore, with a good understanding of depositional settings and high resolution sequence stratigraphic subdivision of strata, predictions of depositional connectivity trends at all stratigraphic hierarchical levels can be made. All connectivity trends at sequence and systems tract stratigraphic hierarchical levels remained the same when the area of the model was reduced by a factor of four and the volume of the model was reduced by truncation below the gas–water contact. Hence, the relationships between the stratigraphic trends and the connectivity trends for the thicker stratigraphic units can be said to be scale invariant. Three-dimensional reservoir models currently provide the best means of quantitatively assessing and predicting reservoir connectivity. However, in low fault density settings, initial screening of reservoir connectivity can be made using connectivity indicators calculated from simple parameters derived from well data such as ‘Thickness divided by Sand/Shale ratio’.

Exploration potential of the mature Southern North Sea basin margins: some unconventional plays based on alluvial and fluvial fan sedimentation models

Basin margins are characterized by clastic, terrigenous accumulations which occur mostly in two morphologically similar but sedimentologically distinct depositional environments: alluvial and fluvial fans. Their differences in sedimentary processes result in distinct reservoir characters and subsurface modelling challenges. The ability to predict, recognize and discern these deposits in the subsurface is therefore the key for effective exploration and development of hydrocarbons. Sedimentary processes characterizing alluvial fan accumulation determine internal reservoir architecture and, ultimately, distribution of porosity and permeability, which however do not change substantially with the distance from apex to toe. Reservoir characteristics however, change considerably if debris-flow or sheet-flooding processes dominate. This distinction is crucial for prediction of reservoir quality, which in the case of a sheet-flood-dominated alluvial fan, can be several orders of magnitude better (higher lateral connectivity and vertical permeability) than a debris-flow dominated alluvial fan. Sedimentary processes on alluvial fans are controlled primarily by the nature of the bedrock and the colluvial deposits of the drainage basin. It is important therefore to understand the palaeogeography and geology of the original basin margin in order to predict reservoir characteristics of alluvial fan deposits. Fluvial fan depositional environments have river-like characteristics, especially in terms of geomorphic features and sedimentary processes. On average they are much larger in size then alluvial fans and internally more variable. Grain-size, texture and facies are controlled by sedimentary processes, which depend on the distance from source area. Proximal fluvial fan deposits may resemble those of alluvial fan in facies and architecture. However, the lower net:gross, lower lateral connectivity and size of sand bodies in the medial and distal area of fluvial fans, will require different geological concepts and therefore different exploration, appraisal and development approaches than alluvial fan reservoirs. Available data inferred from of the Southern North Sea hydrocarbon province indicate that, repeatedly over the geological history, the continental basin margins were characterized by fluvial depositional systems entering the subsiding sedimentary basins. At present, the industry experience in the Southern North Sea in targeting such reservoirs is very limited. However, successful exploration and production activity, especially in the Permian gas basin in The Netherlands and Britain, indicate that reservoirs genetically associated with fluvial fan development have good and commercially sound reservoir quality. Based on this experience and a large number of modern and ancient analogue studies, alluvial fan and fluvial fan ‘unconventional’ reservoirs may represent a high-potential target for the future exploration, especially considering the occurrence of stratigraphical traps both on the southern and northern margin of the Southern North Sea.