In the Fahud field of Oman, the integration between hierarchies of sequence stratigraphic units and fracture systems has proven to be crucial to explain the distribution of flow and mechanical units. The study focused on the Upper Cretaceous, Albian to Lower Cenomanian Natih e unit (Natih Formation, Wasia Group), a 170-mthick carbonate sequence/reservoir, which exhibits heterogeneities in both facies and reservoir quality. Based on a core-derived high-resolution sequence stratigraphic analysis, the Natih e reservoir can be subdivided into four orders of depositional cycles (from 6th- to 3rd-order). Each cycle consists of a transgressive and regressive hemicycle with characteristic facies and rock properties. The facies and diagenetic overprint of the higher-order cycles vary according to their position within the 3rd-order sequences. Analysis of core, borehole images, seismic, tracer and production data indicate a hierarchy of fractures and faults that seems to follow the stratigraphic subdivisions. A relationship between depositional and diagenetic architecture of the cycles, and the aforementioned data, led to the identification of mechanical layering and stratigraphy within the reservoir. This finding was validated and supported by the successful history match of the three-phase production data within the dynamic model of the reservoir. The combination of sequence and mechanical stratigraphy provides a framework for the correlation of facies and mechanical units across the field. Furthermore, the facies and mechanical units are related to reservoir quality and fracture distribution for consistent upscaling into large-scale reservoir models. Through close co-operation between geologists and reservoir engineers utilising dynamic data, it was possible to determine the most appropriate scale for flow and ensure that such a scale was then used as input for dynamic modelling and for planning of the future exploitation of the Fahud field. As a result of this study, Petroleum Development Oman (PDO) has evaluated a 20% increase in risked reserves, and a 25% reduction of well costs.

A group of mature oil fields in Argentina, that share the same sandstone reservoirs, were declining rapidly when applying established methodologies. New wells drilled away from the exploited areas, generally encountered a water column, while infill wells saw either low pressures or injected water. To revitalize these fields, a new approach to both field management and identification of new opportunities was required. This paper discusses the methodologies applied as part of the revitalizing approach, along with the newly identified opportunities.The first of these field studied comprised multiple stacked reservoirs all producing oil through comingled wells; oil production and allocation to date was uncertain. An integrated modelling effort showed unexpectedly that reservoirs containing lighter oil were exhausted; however, the shallower, viscous oil-bearing reservoir (Rayoso Formation) was virtually untouched.To improve the efficiency of the project, one dedicated multidisciplinary team was assigned to identify opportunities over the entire extent of the formation containing viscous oil (~860 km 2 ). The key question was where to find the remaining oil within and across the fields.This work enabled reservoir understanding, developed over a long period of time, during the first study, to be rapidly applied to subsequent ones. Frequent iterations between the static and dynamic models were used to test hypothetical scenarios, to speed up the modelling process and to reduced uncertainty.Use of analogues across the sandstone reservoirs reduced the uncertainty associated with commingled production by comparison with fields where injection and production was reservoir specific. Through analogues we also determined that water was not injected in secondary sands and that this reservoir was being bypassed due to the presence of similar petrophysical properties but lower viscosity oil in underlying reservoirs.This combined fields study resulted in significant new volumes being identified with less effort and time required in respect to studying each field separately, this reducing history matching times (from two years to a number of weeks).As a result of this study, gravity forces and different PVT properties between reservoirs were found to adversely affect production in Rayoso, in addition to the high mobility ratio. A polymer pilot is currently being implemented, with another one currently being planned as the future outlook for these previously rapidly declining fields has now significantly improved.

A number of fields in the Neuquén Basin are currently mature waterfloods. To obtain significant incremental volumes of additional oil, EOR technologies need to be screened and then implemented. Señal Picada is one of Argentina's largest fields with nearly 500 wells in 2013. These wells have exploited all the oil bearing areas of the field and have identified all of the oil water contacts in the various reservoir that make up this field. In 2013 the field was producing with a 96% water cut. Therefore for this field to have a long term future, post waterflood opportunities need to be identified. To accelerate the characterization of such a large field, it was decided to study a sector of the field which was thought to be suitable for an EOR pilot and where an excellent quality core has been acquired. By focusing on a sector, the construction and data QC of both the static and dynamic models was faster than if an attempt was made to construct a full field model. Additionally more iterations between static and dynamic models were possible in less time to identify which variables had the greatest impact on the history matching process and forecasts. With the main reservoir layers characterized, it was possible to both extrapolate the learning to the whole field and to evaluate EOR processes in more detail. The sector modeling demonstrated that 3–4 stratigraphic cycles had the highest potential for EOR. However within these cycles two very different facies were identified by the study, a high permeability sandstone suitable for EOR and a low permeability carbonate which would negatively impact any chemical injection program. The dynamic modeling of the field combined with analysis of the logs of infill wells surprisingly demonstrated that there was significant attic oil potential. This was interpreted as being due to the high vertical permeability in the field resulting in a waterflood which was more affected by gravity forces than viscous forces. In conclusion the sector modeling study characterized the reservoir, identified the key sands with potential for exploitation by EOR and that there was remaining oil to be recovered both by the reduction of the residual oil saturation to water or by improving the vertical sweep efficiency.

Improved oil recovery is more sensitive to sub-log scale heterogeneity than primary recovery processes. Determination of porosity, net-to-gross, saturation and permeability, both magnitude and direction, at scales below log resolution is often required in secondary and tertiary processes and can have an impact on the estimation of original hydrocarbon in place, by-passed oil and recovery factors. Conventional log interpretation and conventional static modeling workflows may not capture sub-scale log heterogeneities, often due to the averaging involved in the upscaling process. Even though log values have been generally calibrated to plug scale (cm3) measurements, they are averaged over volumes much larger than their scale(s) of key heterogeneity. This paper compares the simulated response derived from conventional and from effective property and lamina-scale modeling in three different oil bearing formations in the Argentinian Neuquen Basin, namely Quintuco, Sierras Blancas and Lotena Formations. All three Formations are candidates for waterflood developments and enhanced recovery processes options are being examined. Permeability, porosity, saturation and net-to-gross ratio were determined by constructing high resolution models that enabled capturing sub-log scale heterogeneities. These models were subsequently upscaled at representative elementary volumes and the derived effective properties were used in building simulation models through different upscaling methodologies. Results of the two scale models for each reservoir are compared. Strengths and weakness of the applied methodology, as applied to these specific cases, are evaluated and discussed.

The case study here presented supports the on-going EOR development project of a low net-to-gross fluvial system producing viscous oil form a thick sedimentary column in San Jorge Gulf Basin, Argentina. The selected strategy consists in combining dynamic modeling, analytic tools and field measurements to assess field potential and to model uncertainty through different yet plausible deterministic scenarios. The selected area is Los Perales field in Southern Argentina, with 2880 wells producing from more than 1000 m thick column of thin fluvial sandstone bodies and tuffaceous shale floodplain intercalations. This is a mature field extensively drilled, although single sand extension is likely to be below well spacing. Sands are captured by well logs but have no seismic representation, making connectivity prediction in between wells critical for any IOR or EOR project. For this reason, sand lateral connectivity is estimated by statistical tools, and then several plausible 3D connectivity scenarios are used to model geological uncertainty. Simple analytical tools support simulation results on the identification of key dynamic factors affecting polymer flood incremental volumes. Nevertheless, different modeling approaches are here combined to build deterministic scenarios such as fine scale 2D section models and different resolution 3D sector models for different purposes. We estimate that, given the adverse mobility ratio, when 45% water saturation is reached in the reservoir water sweep efficiency becomes so dramatically low that almost no oil is pushed and water cut raises over 95% as historical production data shows during the 25-year water-flood history in the field. The resulting low recovery factor presents a huge opportunity for polymer flood not only in the already swept areas and heterogeneous regions but also in some unproduced layers with water forecast on swabbing tests. A zone-ranking based on a vertical proportion curve for reservoir and non-reservoir intervals allows us to narrow the development to lower risk confined regions. Further investigation and detail modelling in these regions permit us to assess uncertainty and estimate incremental volumes as up to 3 times those recovered by water-flooding. Production logging confirmed the relevance of targeted intervals in well production, hence supporting polymer business case. This methodology is used to forecast, rank and select the best areas for polymer flood. This integrated approach combines geology, petrophysics and engineering using several laboratory tests, multiple deterministic scenarios and statistical tools to analyze polymer flood opportunities in a large field producing from a low net-to-gross thick sedimentary column.