In the context of harder-to-find reserves and rise in development costs, it is vital that reservoir heterogeneities and compartmentalization be accurately predicted ahead of the drill bit. There are many situations where unexpected compartmentalization negatively impacts reservoir development. This paper used an integration of 3D seismic, well logs, and biostratigraphic data analysis to evaluate compartmentalization in a low well density reservoir (Z-2), onshore Niger Delta. The aim was to identify areas of bypassed hydrocarbon accumulations during production due to compartmentalization. Structural modelling of the Z-2 reservoir identified three intra-reservoir faults that could lead to possible compartmentalization of the reservoir. Z-2 reservoir was interpreted as early transgressive systems tract normal regressive sediments based on sequence stratigraphic techniques used in the modelling. Z-2 reservoir is bounded below and above by layers of shale about 180-200 ft thick, which provides a good seal for the reservoir. Sequential Gaussian simulation algorithm was used to distribute the modelled petrophysical properties in the static model. Modelled porosity, permeability, and NTG ranges are 5-30 %, 1-10,000 mD, and 0.10-0.98, respectively, through all layers. Z-2 reservoir was divided into two flow units separated by approximately 12-ft-thick shale unit, which could act as a barrier to flow between the zones. Fault analysis was done using Shell structural and fault analysis plug-in in Petrel to determine the shale gauge ratio, fault permeability, and fault zone thickness of the relevant intra-reservoir faults. Fault juxtaposition analysis shows sand-on-sand juxtaposition at the fault tips. Further analysis shows that fault thickness is within the gas crossflow range of (0-0.6 ft) and shale gouge ratio for all three faults falls within the ranges of 0-100 % with a significantly higher percentage of the areas below 35 % in fault 3. Fault 1 will not allow gas crossflow, while \20 % of the juxtaposed areas in fault 2 are within the range to permit gas crossflow. Fault 3 which has a low SGR and high permeability relative to the other faults is not interpreted to be sealing. Fault zone permeability for parts of fault 1 is \1 mD while parts of faults 2 and 3 are [1 mD. The Z-2 reservoir stands the risk of being compartmentalized into two hydrocarbon accumulations ('X' and 'Y') during production. The total GIIP for Z-2 is 1668 Bscf and with the present well positions and configurations; the production of about 20 % of the GIIP is at risk of being bypassed. Future wells should be planned to appraise 'X' and 'Y' accumulations.

Successful oil and gas field development in clastic reservoirs is usually dependent on the amount of subsurface data available to be evaluated during field maturation. The general rule is that more data reduces subsurface uncertainties. This invites expensive appraisal campaigns that invariably leads to delays in investment decisions and increased costs in development projects. The present study highlights how the understanding and definition of the architecture of the reservoir coupled with the use of analogue database as a methodology can be used to enhance hydrocarbon development in fields that are not fully appraised. The un-appraised Kz field is used as a case study. Kz field, with an expectation In-Place oil of ca. 1150 MMstb is located SW of the Kashagan field in the Caspian Sea, Kazakhstan. The field consists of 11 stacked hydrocarbon-bearing reservoirs of varying thicknesses penetrated by a single exploration well. Due to the paucity of well penetration, subsurface uncertainty that impact on hydrocarbon volume and recovery is high. The methodology used was to combine the wells log and core data in addition to the use of sequence stratigraphic technique to derive sedimentological conceptual models. Analogue databases were then used to derive a geological meaningful range of dimensions for the geometry of the respective sand bodies. These ranges were then used an input for in-place volume ranges. Evaluation results showed a volume range that could support a go-forward decision for further investment in the field. Based on these results, some preliminary field development decisions were taken prior to dynamic simulation. Decisions include; (i) Drill six wells (ii) Do Multi-zone Well Completions and (iii) use two drill centers to optimally develop the field (Phase-1). The key strength of this approach is that some key Field Development decisions can already be made before appraisal using basic sedimentological concepts and analogue database studies.

Field X is one of SPDC's major gas fields located onshore of Nigeria with six well penetrations and two key reservoirs, A1000X and B4000X,. The field is covered by a 1992 3D seismic reprocessed PSDM with relatively poor imaging quality. This caused uncertainties with respect to the interpretation of possible intra-reservoir fault compartmentilization. These intra-reservoir faults are on the footwall of two major southern and eastern boundary faults. To optimally develop these reservoirs, it was proposed to drill an appraisal well in the eastern fault block, modelled as a reservoir compartment, and subsequently carry out an interference test to establish the lateral hydraulic connectivity of the reservoirs. A new seismic data was acquired and processed to resolve the uncertainties associated with the poor imaging quality of the 1992 seismic. The interpretation of the new seismic showed similar structural trend, albeit with better clarity of the subsurface images in the fault shadow zones.  It also showed continuous seismic reflection loops suggesting a more better lateral reservoir connectivity To better understand the reservoir lateral hydraulic continuity, a multidisciplinary integrated study was conducted using all available data (production tests, Seismic and Petrophysical data). This paper covers the multi- disciplinary work carried out to establish the lateral connectivity of the reservoirs and its significant cost reduction to the total project cost.

Field development is heavily contingent on the proper delineation of the field's resource volume along with the subsurface uncertainties. For green fields, appraisal drilling reduces uncertainties, but has the potential of cost escalation and delays in project timelines thus making projects less competitive. This study highlights how a fast tracked appraisal/development strategy for 1.7 Tcf of gas development project worth $800mln was developed and approved by the regulatory authorities. The GATOE field under review is in the South East of the Niger delta, Nigeria. The field is 80 km2 in aerial extent. It consists of 11 stacked hydrocarbon-bearing reservoirs of varying thicknesses and, is penetrated by 5 wells. Seven (7) of these reservoirs (3 AG and 4 NAG) with GIIP of 900 Bscf that are ‘ready-to-go’ gas resource were captured in the ‘Tranche-1’ development scope. The remaining 4 reservoirs which are AG reservoirs with uncertainties in the actual oil column were grouped for trench-2 development but will be appraised during the Tranche-1 execution phase. Usually regulatory approval for field development is secured post appraisal drilling. This study however, proposes a concurrent field development and appraisal scheme where development wells (for fairly known reservoirs) are used to also appraise reservoirs with appraisal needs. Thus significantly reducing the number of appraisal wells (from 3 to 1) and ensuring the delivery of fast-tracked field development (early ‘First-gas’ date). The only appraisal well will be drilled at the tranche-1 execution stage. In order to achieve this, a multidisciplinary evaluation of all available data was done in addition to the use of reliable technology. This is with the aim of demonstrating that the fast-tracked gas development will not jeopardise the recovery of any potential oil that may be proved from the appraisal exercise. This study demonstrates the viability of a field development strategy in which ‘freezing’ of a development concept prior to full field appraisal can be achieved. The outcome is a massive reduction in appraisal costs and accelerated field development.

Critical decision making with limited information and associated uncertainties is a challenge at every level of the hydrocarbon value chain. This is even more so at early stages of field development projects when geosciences and engineering data are sparse and the understanding of the geological complexities is still limited. Thus, the need for building multiple realizations of representative reservoir models that captures the full range of subsurface uncertainties is crucial to ensure a robust decision-making process.From previous studies, the Reservoir Complex, X is highlighted as a stack of two gas-bearing reservoirs that merge to form a doublet as observed on seismic and share a common contact towards the flank of the structure. This interpretation informed the modelling of both reservoirs as a single mega unit. An Integrated Reservoir Modeling approach rather than a discipline-focused one was adopted to evaluate the range of uncertainties in the reservoirs. For this study, a multidisciplinary subsurface team built a scenario-based model and performed Sensitivity analysis to identify key uncertainties on input parameters that are most impactful on in-place volumes and recoverables.This paper discusses techniques employed in building the static/dynamic models, generating estimates for the various uncertainties and how these were analyzed to identify the 'heavy hitters'. Results from this study identified Structure, Net-to-Gross and Porosity as the top three uncertainties with most impact on static volumes while Structure, PVT and Aquifer size have most impact on recoveries.Deterministic low, base and high case In-place volumes computed are 509, 627 and 769 BScf while recoveries were 182, 339 and 643BScf respectively. Probabilistically, the in-place volumes were 336, 480 and 634 Bscf while the recoverables were 205, 348 and 550 Bscf respectively.