Abstract It is common practice to incorporate deterministic transmissibility multipliers into simulation models of siliciclastic reservoirs to take into account the impact of faults on fluid flow, but this is not common practice in carbonate reservoirs due to the lack of data on fault permeability. Calculation of fault transmissibilities in carbonates is also complicated by the variety of mechanisms active during faulting, associated with their high heterogeneity and increased tendency to react with fluids. Analysis of the main controls on fault-rock formation and permeability from several carbonate-hosted fault zones is used to enhance our ability to predict fault transmissibility. Lithological heterogeneity in a faulted carbonate succession leads to a variety of deformation and/or diagenetic mechanisms, generating several fault-rock types. Although each fault-rock type has widely varying permeabilities, trends can be observed dependent on host lithofacies, juxtaposition and displacement. These trends can be used as preliminary predictive tools when considering fluid flow across carbonate fault zones. Fewer mechanisms occur at lower displacements (<30 m), creating limited fault-rock types with a narrow range of low permeabilities regardless of lithofacies juxtaposition. At increased displacements, more fault-rock types are produced at juxtaposition of different lithofacies, with a wide range of permeabilities.

Abstract Reservoir Compartmentalization – the segregation of a petroleum accumulation into a number of individual fluid/pressure compartments – occurs when flow is prevented across ‘sealed’ boundaries in the reservoir. These boundaries are caused by a variety of geological and fluid dynamic factors, but there are two basic types: ‘static seals’ that are completely sealed and capable of withholding (trapping) petroleum columns over geological time; and ‘dynamic seals’ that are low to very low permeability flow baffles that reduce petroleum cross-flow to infinitesimally slow rates. The latter allow fluids and pressures to equilibrate across a boundary over geological time-scales, but act as seals over production time-scales, because they prevent cross-flow at normal production rates – such that fluid contacts, saturations and pressures progressively segregate into ‘dynamic’ compartments. Thus, reservoir compartmentalization impacts the volume of moveable (produceable) oil or gas that might be connected to any given well drilled in a field, which restricts the volume of reserves that can be ‘booked’ for that field. Booking of reserves is tightly regulated by government authorities because it is a key measure used by stock analysts and investors to value an oil company. This places reservoir compartmentalization studies, and the predictive science and technology applied to them, at the heart of company valuation. Unexpected compartmentalization can also seriously impact the profitability of a field: with more data acquisition, more study, more wells, more time being required to produce less oil and gas than was originally anticipated. In extreme cases, this might even lead to early field abandonment.

Abstract As an industry we have been poor at identifying and predicting the effect of reservoir compartmentalization on fluid flow throughout field life. In the context of harder-to-find reserves and rising development costs it is vital to have a well-rounded strategy in place to identify and mitigate uncertainties and risks associated with compartmentalization. The key challenge of today is therefore to improve predictive capability. Historically we have relied too heavily on ‘single complex’ linear modelling approaches to understand the impact of compartmentalization. Lately, we have begun to place a greater emphasis on using a forensic level of reservoir analysis coupled with the use of dynamic signals from production data and constant down hole monitoring of fluid-type, pressures and temperatures. Evidence is mounting that as fields deplete they evolve mechanically over production time-scales leading to changes in fault behaviour, stress configuration, compaction and hence compartmentalization; such factors are commonly not predicted at start-up. Our challenge has been to develop toolkits and workflows which integrate an appropriate range of geological models iteratively coupled with dynamic data. We need to develop analytical approaches that enable real-time updates from the evolving reservoir & fluid system to iteratively modify our models and improve their predictive power. This will allow us to make better-informed decisions at every stage of field life.

Abstract This paper examines the impact of compartmentalization on oil recovery, the importance of identifying it during field appraisal, and methods to evaluate it using fluid data. The impact on recovery factor is highlighted using a global database of oil field recovery factors as a function of reservoir complexity and compartmentalization, and emphasized in two case studies. The effect of compartmentalization on oil recovery demonstrates the benefit in characterizing compartmentalization correctly during appraisal, so that the field can be developed in an optimal manner. Early characterization of field compartmentalization requires making maximum use of available fluid data during appraisal. When interpreting fluid data to identify compartmentalization, it is critical to take into account the different time-scales for various fluid signals (pressure, contacts, density, composition) to equilibrate, and to be able to extrapolate to field production time-scales. This is essential to avoid false negatives (compartments assumed absent due to homogeneous fluid properties, when in fact fluids would have equilibrated even in the presence of compartments), false positives (where fluid differences are interpreted as evidence of compartments when in fact there has not been sufficient time for equilibration to occur), and to resolve apparently conflicting data (some fluid indicators are at equilibrium, others are not). Rigorous simulation of fluid equilibration is a complex multiphase multidimensional process, and is generally reserved for specialist in-depth studies. However, order-of-magnitude evaluations can be made using analytical solutions in minutes, allowing many ‘what-if’ scenarios to be considered and uncertainty to be assessed. Analytical solutions for estimating the time required for spatially-varying fluid properties to revert to steady state distributions are reviewed. All these mixing processes are shown to be diffusive in character. An effective diffusion coefficient for each process can be calculated from the reservoir rock and fluid properties. For an isothermal system, the different time-scales and distances for each fluid-property variation to attain equilibrium can be compared on a single graph. Where the time elapsed since fluid-perturbation is known, analytical solutions can be used to estimate the degree of compartmentalization (e.g. permeability of barriers). These solutions lend themselves to the development of simple practical compartment-assessment tools for industry practitioners.

Abstract Compartmentalized reservoirs can be identified based on a variety of criteria most commonly using structural geometries and stratigraphic barriers. This paper reviews several case studies from West African fields in which an additional variable, fluid chemistry, is used to identify compartmentalization at an early stage in the production history. Fluid characterization is important to constrain productivity, connectivity, facilities planning, and commercial value. Near-critical, single-phase fluids offer a case in which underestimation fluid PVT behaviour and variability can have a significant impact on all of these elements – resulting in incorrect interpretations of resource type and distribution.

Abstract The present study illustrates the multi-disciplinary integration of time-lapse geochemistry with 4D seismic, production logging and pressure history analysis in the Auger Blue reservoirs. The integrated approach enables identification of dynamic fluid reservoir communication occurring after six years of primary production between an oil (Lower Blue O2) and a gas reservoir (Blue O Massive) indicated by pressure data as separate at static conditions, and points to cross-fault leakage with possible stratigraphic communication as the likely mechanism(s) by which dynamic fluid reservoir communication has occurred. The time-lapse geochemistry study was performed utilizing fluid samples collected during a period of over eight years of primary production. The results present evidence for gradual mixing of Lower Blue O2 oil with the condensates of the Blue O Massive reservoir. Time-lapse geochemistry results also pinpointed the timing when dynamic reservoir communication started to occur, with an initial mixing detected as early as six years after the start of production. Statistical evaluation of the geochemistry results showed the contribution of the oil to the gas condensate reservoir to significantly increase from 14–23% to 60–63% within a year from when mixing was initially detected. The results of the study assisted in implementing an improved field development strategy to increase production.

Abstract Drainage cells are localized reservoir volumes that are bounded both laterally and vertically by permeability barriers. The subdivision of a reservoir volume into drainage cells provides a framework that allows a mature producing field to be screened for remaining oil volumes. Nine drainage cells have been defined in the Nelson field. The lateral edges of these drainage cells are stratigraphic in nature and correspond to the boundaries between individual macroforms, for instance, between channel complexes and interchannel sediments. A very large dataset of produced water chemical analyses has been used to help define the extent of the drainage cells. Provinciality, shown by areal variations in produced water compositions, is consistent with the inferred location of the cells. The Nelson field shows variation in the chloride ion concentration of produced water both vertically and laterally. Vertical variation can be detected by changes in produced water chemistry after water shut-off events at shale horizons which are thought to be laterally extensive within the reservoir. Lateral variation corresponds to patchwork areas that are consistent with individual macroforms such as channel complexes. An additional technique has been used to confirm the location and extent of drainage cells within the field. This involves the compilation of drainage charts, a quantitative volumetric method that involves comparing theoretical and actual oil–water contact changes within particular field areas.

Abstract This paper discusses integration of production surveillance techniques, focusing on the use of 4D seismic data to identify reservoir compartmentalization. We present two examples of recently drilled compartments that were successfully identified following integration of surveillance data with detailed reservoir modelling work. Our examples are from the faulted, Paleocene channelized turbidite reservoirs of the Schiehallion oil field, offshore West of Shetlands, U.K. The first example provides a good case history of a 4D Integrated Reservoir Modelling (4D IRM) approach – which involved integration of dynamic well data with 4D seismic, and iterative revision of geological and reservoir simulation models. Two newly identified targets were drilled and completed successfully using these techniques. The second example illustrates a situation where 4D seismic interpretation was key in identifying a new infill target. Production in the Schiehallion Field started in 1998, and the current development scheme totals 46 wells (22 producers and 24 water injectors). During the early years of production it became apparent that geological connectivity, fluid flow and pressure communication between wells was not as inter-connected as expected. As a result the number of wells required to maximize the recovery has more than doubled to that specified in the original development plan, and the number is expected to increase further as the field matures. Continuous collection of bottom hole pressure data from permanently installed gauges, well testing and production logging (PLT) supported by a regular time-lapse (4D) seismic programme are used to update conceptual thinking and thus constrain geological and flow simulation modelling. This data integration results in improved understanding of the static and dynamic reservoir compartmentalization and well connectivity.

Abstract The Azeri field in the South Caspian Sea, offshore Azerbaijan, is a periclinal anticline 20 km in length containing multiple stacked reservoirs of Pliocene age. Appraisal wells that were drilled at the eastern end of the structure identified multiple oil–water contacts and fluid pressure gradients in both of the principal reservoirs, the Pereriv B and D. At the time, these data were interpreted to indicate the presence of compartments at the eastern end of the field as a result of sealing faults within the aquifer. This local compartmentalization seemed to be in marked difference to the majority of the field where pressure connectivity had been observed. A new analysis of the pressure data for the Pereriv B shows that aquifer pressures at sea-level datum define a simple water potential gradient. As a result of this, the oil–water contact in this reservoir is gently inclined towards the NNE. The precise inclination and orientation of the oil–water contact has been determined geometrically using the depths and coordinates of free-water levels and oil–water contacts from around the field. The best-fit inclined oil–water contact for the Pereriv B also provides a good fit to the contact observed from seismic amplitudes. The new analysis provides a more optimistic view of reservoir connectivity, and the conceptual geological model for the eastern end of the field is now consistent with observations made in the rest of the Azeri field.

Abstract The Pierce Field in the Central UK North Sea is a twin diapir structure that produces from the Paleocene Forties Sandstone Member (Forties Sandstone). Different hydrocarbon–water contacts encountered in the wells around both diapirs have been variously ascribed to a hydrodynamically tilted oil–water contact or else some form of stepped (compartmentalized) contact. Recent reinterpretation of the structure, sedimentology and fluid geochemistry has indicated that the stratigraphic architecture of the reservoir is the prime control on fluid flow over both geological and production time-scales. These depositional architectures deflect the hydrodynamic flow of aquifer water around the field, resulting in a modified-tilted-contact. The same depositional architectures control the flow of fluids under production. The Forties Sandstone was emplaced by turbidity flows influenced by pre-existing seafloor topography that funneled the flows into discrete sediment corridors and into the Pierce area. The rising twin diapirs further influenced the flows by forming: (a) a small salt withdrawal basin between the diapirs that captured sediment; and (b) enough seafloor topography to prevent the bulk of the flows from depositing significant amounts of sand over the crest of the diapirs. Because the bulk of the high permeability sands were deposited in a rim around the diapirs, the aquifer and injected water does not always flow to structurally higher elevations, but follows the geometry of the channelized sands. While faults are present on both South and North Pierce, they are not extensive and do not appear to play a major role in the compartmentalization of the field. From production data, pressure communication can be inferred around North Pierce and around the majority of South Pierce, the main exception being a block bound by large throw faults in the SE of the southern diapir. Geochemical fingerprinting of the hydrocarbons in Pierce shows families of oils that suggest that the northern and southern parts of the reservoir are separate oil compartments, which is a result of the interaction of the filling history and the stratigraphic and structural architecture of the reservoir.

Abstract The Lower Sendji Carbonate (Albian age) of the N’Kossa field is a mixed siliciclastic–carbonate reservoir exhibiting very heterogeneous reservoir properties and the development of extensive vertical flow permeability barriers. The reservoir is a succession of interstratified dolomite, limestone, sandstone and shale lithologies of sabkha, tidal flat and lagoonal origin. Early, synsedimentary dolomite cements are extensively developed, particularly over local palaeohighs. Challenges to hydrocarbon production include: (1) the vertical variability of reservoir properties; (2) the presence of many, laterally extensive vertical flow barriers; and (3) variable connectivity between fault-bounded compartments. This complexity was underestimated at the appraisal stage, the initial development plan calling for a relatively simple scheme of pressure support to the critical reservoir fluid via injection into the gas cap and the water leg. This decision was supported by the identification of a single hydrocarbon column (>400 m thick) over the entire structure which suggested a lack of vertical compartmentalization. Recent studies, which include a geological synthesis of more than forty wells and a dynamic data synthesis to determine the production mechanism and identify key heterogeneities, show a lack of pressure support to the oil leg from both water and gas injector wells. Today, integration of static and dynamic data together with an improved geological understanding of the stratigraphic control on vertical flow barriers and mapping of high permeability sandstone layers is the key to identifying unswept zones of the field and future infill drilling targets.

Abstract This paper describes the nature and relative significance of stratigraphic and structural compartmentalization in dryland fluvial reservoirs using data drawn from the Heron Cluster (Heron, Egret and Skua) oil fields in the UK Central North Sea. The Triassic Skagerrak Formation reservoir in these fields was deposited in a variety of dryland terminal fluvial settings, ranging from relatively arid terminal splay and playa to more vegetated, channel-confined systems with associated floodplain and palustrine facies. Laterally extensive floodbasin shales punctuate this terminal fluvial architecture. Static and dynamic data indicate that these fields are compartmentalized: geochemical data indicate significant fluid variations both between wells and vertically within individual wells; material balance calculations suggest production from restricted connected volumes, locally from a subset of the range of oils present; and re-perforation across significant shale boundaries access undepleted reservoir with different fluid compositions. Lateral variations could be ascribed to prominent structuration within these fields, but in general these high net:gross reservoirs do not have a viable fault seal mechanism. Early (syn-halokinetic) grounding of Triassic ‘pods’ between salt swells during salt withdrawal has resulted in zones of intense faulting along the zone of contact of the pod and the underlying basement, and also on the flanks of pods as the margins collapsed under further salt withdrawal. This deformation occurred under relatively shallow burial depths and is largely expressed by disaggregation zones and phyllosilicate fault rocks. Fault property averaging algorithms (e.g. shale gouge ratio), indicate that the sands should communicate across the juxtapositions, implying that the fluids and pressures should equilibrate between reservoir sands. However, the stratigraphic differences across major shales in both fluid geochemistry and pressure caused by draw-down are preserved despite the presence of these faults. The preservation of stratigraphic compartments indicates that for these faults the deformation mechanism was probably dominated by clay smear, in which the shale-prone sequence was smeared down the fault planes without losing its coherence. This style of stratigraphic compartmentalization occurs across several shale-prone intervals that are correlatable across the region. In some cases these mark the boundaries to major changes in fluvial depositional character, provenance and floodplain drainage, suggesting an extrinsic control that led to shale packages defining consistent barriers in all the fields. Other shale barriers do not show major changes in depositional character and, although correlatable, appear to be the product of semi-regional advance and retreat of the fluvial systems, possibly combined with nodal avulsion. In contrast to reservoirs deposited by large exorheic rivers, the terminal nature of these dryland fluvial systems appears to have resulted in the repeated interfingering of fluvial and floodbasin facies over a scale of many tens of kilometres. As a result such terminal fluvial reservoirs are prone to stratigraphic compartmentalization. However, thinner shales are prone to breaching by fluvial erosion and as a result not all correlatable shale events form barriers and only a subset will compartmentalize. Mitigation against this compartmentalization requires a development strategy where well trajectory and perforation maximizes stratigraphic exposure.

Abstract Marginal marine depositional systems exhibit stratigraphic reservoir compartmentalization potential at three hierarchical scales. At each of these scales, stratigraphic compartmentalization potential can be related to the dominant depositional processes and accommodation:coarse sediment supply ratio (A/S) that are acting at the time of deposition. All three orders of compartmentalization potential must be considered in order to define optimal field development plans and completion strategies. The lowest order of compartmentalization is usually at the inter-parasequence scale. The parasequence is represented by a conformable succession of strata separated by marine flooding surfaces and as such it generally defines the basic flow unit in marginal marine systems. In systems tracts associated with relatively high A/S ratios, for example late Lowstand, Transgressive and early Highstand (steeply rising shoreline trajectories), vertical compartmentalization potential is relatively high because of the enhanced preservation potential of flooding surface shales under these conditions. In systems tracts associated with relatively low A/S ratios, for example late Highstand, Falling-stage and early Lowstand (flat, slightly rising and falling shoreline trajectories), vertical compartmentalization potential of parasequences is reduced because the potential for erosion of flooding surface shales by overlying deposits is high and hence potential for vertical sand–sand contact between parasequences is enhanced. The second level of compartmentalization hierarchy is the inter sand-body scale. Individual sand bodies are defined within parasequences. The lateral connectivity of these sand bodies is a product of the dominant depositional processes active at the time of their deposition (wave, tidal, fluvial). Wave-dominated systems tend to produce more laterally continuous sand bodies, fluvial-dominated systems more laterally restricted sand bodies and tide-dominated systems both laterally continuous and laterally restricted sand bodies. Vertical compartmentalization potential of these reservoir sand bodies is related to A/S regime. In high A/S regimes, sand bodies are more likely to be disconnected or compartmentalized. In low A/S regimes, erosional amalgamation of sand bodies is more likely thereby leading to lower compartmentalization potential. The third order of potential stratigraphic compartmentalization is the intra sand-body scale. This scale is represented by intra sand-body heterogeneities such as dipping or horizontal shales, carbonaceous-rich beds or laminae, shale abandonment plugs of channels and carbonate concretions. In high A/S regimes the preservation potential of these heterogeneities is relatively high leading to an enhanced potential for intra sand-body compartmentalization. Lower A/S regimes result in a greater likelihood of lateral and vertical erosion of these heterogeneities leading to a higher potential for reservoir connectivity.

Abstract The connectivity of a reservoir to a well-bore represents a fundamental initial condition for drainage of an oil or gas field. The size of the static connected volume is a function of the stratigraphic and structural architecture of the reservoir. The most important stratigraphic factor affecting connectivity is a net-to-gross threshold which determines whether a reservoir is highly or poorly connected. Other stratigraphic factors affecting connectivity are those that impact the reservoir dimensionality (for example, compartmentalizing continuous mudstones or parallel channel deposits) and the size of geobodies relative to the total reservoir size. Structural compartmentalization may cause fault compartments that are too small in volume to support reservoir connectivity: as the size of the geobodies approaches compartment size, connectivity is typically less predictable. Static connected volumes alone do not predict flow performance, but are a component in predicting flow performance. To more completely address predictions of flow performance, dynamic connectivity is sometimes considered. However, dynamic connectivity, which is dependent on fluid type, permeability heterogeneity, time and other factors, confuses connectivity with tortuosity and sweep- and displacement-efficiency and is probably best avoided. Finally a connectivity flow diagram is proposed as a guide to help formulate key questions concerning uncertain reservoir parameters affecting reservoir connectivity.

Abstract Calibration is a necessary step in the workflow for prediction of fault seal because there is no direct way to detect the hydraulic behaviour of a fault at the scale of a hydrocarbon trap. Over the last 20 years two general approaches have been developed: Measurement of hydraulic properties of fault-zone samples (lab calibration), then mapping these results onto the appropriate parts of trap-bounding faults. Design of simple algorithms which attempt to capture a salient feature of the fault zone (e.g. CSP, SSF, SGR), then looking at known trap-bounding faults to find a relationship between the algorithm and the presence or capacity of a seal (sub-surface calibration). Seal capacity is typically described by Hg–air threshold pressure in the lab or static pressure differences in the subsurface (e.g. hydrocarbon buoyancy pressure). In addition to likely interpretation and geometry errors in approaches (i) and (ii), further uncertainty is introduced when converting the calibrated seal strength to potential hydrocarbon column height, because of the variability of subsurface hydrocarbon fluids (interfacial tension). Despite these potential problems, the different methodologies typically agree reasonably well in their predictions for fault-seal capacity. However, this agreement may be largely coincidental and is likely to be a response to the heterogeneity of fault-zone structure (especially at intermediate ‘compositions’ or SGR).

Abstract The effective computation and visualization of cross-fault sealing or flow, and parameters that infer or control that distribution, is a key step in the production of more reliable exploration and production simulation models. A better understanding of the impact of fault-related flow or baffling through visualization can lead to the development of more robust and useful geological models that better define the likely range in flow behaviour. A range of visualization tools are available, from the traditional fault plane juxtaposition map to the vector visualization of cross-fault fluid flux. Each tool has its applications and limitations. In this contribution we discuss the application of these different techniques and highlight situations where these are particularly successful. A number of existing visualization approaches will be reviewed and improvements to those techniques are shown. A series of existing property visualization techniques are critiqued, such as the imaging of shale gouge ratio (SGR) and fault transmissibility multipliers (TMs) on the fault faces, both of which are limited in their ability to act as a proxy for cross-fault fluid flux in many circumstances. Fault rock property visualizations, such as hydraulic resistance and fault transmissibility, are presented. More direct and hence more powerful indications of probable cross-fault fluid flux are also described, such as the effective cross-fault transmissibility (ECFT) and the effective cross-fault permeability (ECFP). These static proxies for cross-fault fluid flux are compared against back-calculated and visualized cross-fault fluid flux values derived from either streamline or full flow simulation data. The ECFT is shown to provide a useful and rapid indication of likely fluid flux from the static model; however, the direct imaging of cross-fault fluid flux derived from simulation results allows for a far better understanding of how the faults have contributed to the reservoir flow simulation result. Visualizations of the fault- and flow-related properties: (a) on the fault face; (b) in the grid cells adjacent to the fault face; (c) as vectors; or (d) as fault-wide summations, all provide useful insights for different parts of the reservoir evaluation workflow. This contribution highlights a series of new and efficient techniques to image and hence improve the understanding and modelling of fault sealing in both exploration and production settings.

Abstract Despite their significance, structural parameters are sometimes neglected in assessments of uncertainty on connected volumes and forecast production for compartmentalized reservoirs. A workflow is proposed for modelling multiple realizations of fault geometry and properties using 3D geomodelling software. Geometrical parameters that may be simulated include fault and horizon shape and location, fault displacement and fault pattern, while property variables include fault permeability, thickness and clay smears. Realizations are ranked by estimated connected volume, with selected models being exported for numerical flow simulation. Experimental design is used to assess sensitivity of forecast production and pressure to different parameters. The workflow is illustrated using a North Sea reservoir, in which structural heterogeneities cause considerable uncertainty on connected volumes, with implications for history matching and infill well planning. Fault geometry and permeability were the most important properties for all studied responses, however their relative significance could vary between early and late field life. A number of improvements are proposed, chiefly in the areas of connected volume estimation, handling of uncertain grid geometries and calculation of stress- or saturation-dependent fault permeabilities. Finally, the method can be integrated with conventional sedimentary and petrophysical uncertainties to investigate interactions and relative sensitivities with regard to structural parameters.

Abstract Since the discovery of the Groningen field, fifty years ago, more than 250 gas fields have been discovered in the Netherlands. A study of most of these fields shows that connected volumes are often smaller than expected from volumetric evaluation. Seismic uncertainty can often be argued as an explanation for the discrepancy, but there may be also a geological explanation. Most gas fields are found in the Permian Rotliegend and good drainage is expected because the reservoirs are relatively thick and homogeneous. Minor faulting is often thought to cause drainage problems, but this study shows it is likely in a number of cases. Twenty three Rotliegend fields with connectivity problems have been studied in part of the Dutch offshore. This analysis outlines a number of regions in the Rotliegend fairway that share a risk for fault seal and therefore reduced connected volumes. Fault seal analysis is important to understand compartmentalization but does not explain all discrepancies. In a number of regions, fault seal analysis is unsuccessful because cataclastic sand-to-sand sealing strike–slip faults are difficult to detect. Stratigraphic compartmentalization is seen to play a role in some well defined areas of the basin. A better understanding of the connectivity problems can highlight areas attractive for appraisal and near field exploration.

Abstract Multi-fault analysis is an ExxonMobil stochastic tool for analysing the impact and sensitivities of stratigraphic uncertainty and variability on cross-fault leakage of hydrocarbons in faulted traps. This juxtaposition-based method provides quantitative prediction of hydrocarbon contact levels through a complex system of structural spills and juxtaposition leak points in traps with stacked reservoir systems and one or more faults. Validation of the Multi-fault analysis technology was carried out by comparing pre-drill predictions to post-drill results from 41 faulted exploration prospects drilled from 1994–2001. Of the 41 prospects, 29 were valid tests in which we made 22 successful predictions. Of the 22 successful outcomes, 11 were discoveries and 11 were dry wells. Some of the dry wells were drilled assuming the presence of sealing fault-zone material to trap hydrocarbons despite a Multi-fault analysis failure prediction. The seven Multi-fault failures comprise four predicted successes that were failures and three predicted failures that were successes. Most of the Multi-fault prediction failures can be attributed to data quality and uncertainty; however, some may be associated with sealing fault-zone material. Other considerations in fault seal analysis (i.e. dip leak along faults and sealing fault zone materials), model input uncertainties, and using drill-well learnings are also discussed.