Objectives/Scope The deep water Bonga development is situated in block OML118 offshore Nigeria, . The Bonga Main Field was discovered in 1995 with first production in November 2005. The main reservoirs are channelized, unconsolidated, turbidite sandstones of Miocene age. While the field development has been successful, opportunities and challenges remain. Below the producing reservoir levels, there is potential for additional reservoirs - unlocking those deep hydrocarbons would require to drill beyond present well control. At the same time, drilling development wells cost effectively has remained challenging even for shallow intervals given subsurface heterogeneities, which often cause borehole stability issues. Methods, Procedures, Process This study introduces a novel workflow that allows the asset to leverage quantitative seismic interpretation, that is closely integrated with geomechanics modelling to address both the deep reservoir potential opportunity and the borehole stability related drilling cost challenge. Here we focus on the integration of the geomechanical and geophysical data and workflows rather than on the successful prediction of deep sand probabilities using seismic AvO inversion and Bayesian facies classification. As part of the seismic inversion, 3D dynamic Young's Modulus and Poisson's Ratio volumes were derived. In parallel, a finite-element mesh for geomechanical modelling was created from the structural interpretation and then populated with the seismic derived rock properties. The resulting field scale 3D geomechanics model helps to address production-related challenges such as top seal integrity, fault reactivation, compaction, subsidence, injection, depletion, borehole stability, and sand control. For this study, seismic data needed to be inverted over an interval from near seabed to deep targets below well penetration - some 3 seconds TWT or 10,000ft, a much larger window than normal for single reservoir-focused studies. Seismic AvO inversion was run using overlapping, time windows from shallow to deep, to account for wavelet transmission effects. The resulting inversion outputs, acoustic and shear impedance, were used to derive shale and sand probability volumes. Well based analysis was used to determine the best relationship between acoustic and shear impedance and Young's Modulus for both sand and shale facies. Using the facies probability volumes from seismic inversion, 3D dynamic Young's Modulus and Possion's Ratio volumes were calculated from the acoustic and shear impedance volumes. Results, Observations, Conclusions A 1D geomechanics model, calibrated against drilling experience, was used to convert from dynamic to static Young's Modulus. Finite-element geomechanical modelling was used to produce the 3D stress model combining pore pressure, structural information, seismic-based static rock properties, and far-field horizontal stresses. The final stage of stress analysis involved calculating stresses that honor local field measurements and incorporate regional trends. Novel/Additive Information Utilizing 3D finite element models constrained by seismic yielded a high resolution predictive model that will significantly improve wellbore stability predictions along the paths of future development wells. The business impact for the Asset is reduced development well costs by having a more predictable geomechanics model, fully constrained by lateral variations from 3D seismic data, and greatly reduced cycle times for borehole stability predictions for future wells.

The presence of a large gas cap in an oil reservoir usually presents unique depletion challenges and opportunities. While the gas provides a significant source of drive energy that contributes to oil recovery, the expansion of the gas cap typically leads to gas cusping or coning, potentially resulting in lower than optimal recovery. This case study is a large reservoir with a complex combination of stratigraphic and structural trap. The reservoir consists of middle Miocene stacked and slope-confined deepwater turbidite channel complexes. Three major canyon-type channel complex sets can be distinguished in the field, each consisting of smaller channels that display a certain degree of amalgamation.The initial depletion strategy for shallowest channel complex reservoir with limited aquifer was gas injection updip of producing wells. However, the steady ingress of gas from the crestal gas injector (as seen in 4D), into one of the most prolific wells located in this voidage region has resulted in decline of the well productivity due to increasing GOR. Moreover, the field is produced under a strict gas processing capacity and the increased gas production from the shallowest channel backs out oil production from other channelized reservoirs. To counter this GOR increase, a downdip water injector was proposed.The study evaluated the impact of simultaneous updip gas injection and downdip water injection in the subject reservoir using reservoir simulation. Analysis showed that the introduction of downdip water injector in addition to the existing gas injection resulted in an overall 2% increase in the field EUR. The increase was largely attributed to the observable reduction in the well GOR with corresponding production boost, in addition to creating gas ullage for other wells in the field. This expected gain was sufficient to justify the cost of a deepwater infill injector well.

Following the 2010 Gulf of Mexico Macondo well control incidence, increased emphasis has been placed on the safe delivery of wells. Fracture pressure prediction is a critical input to effective well planning and safe drilling especially in deepwater environments due to rising well costs and narrower drilling margins with increasing water depths. Therefore, accurate formation fracture and pore pressure prediction is crucial to minimize potential borehole stability concerns, lost circulation problems and optimize casing setting depths during drilling. Also, for fields where water flooding is used to enhance recovery or maintain reservoir pressure, proper estimate of fracture pressure is necessary to curtail implications such as loss of production, injectivity and reputational damage in the event that there is loss of containment and hydrocarbons migrate through to surface. This work establishes empirical correlations for fracture pressure prediction from field leak–off tests data; builds on existing foundations relating fracture pressure with overburden, in-situ effective stress ratio and pore pressure. The results indicate that the developed correlations can be suitably applied in offshore fields in the Gulf of Guinea deepwater environment.

The Bonga field is in its late stage Phase-3 development. Infill wells are drilled to target oil in the bypassed or unswept areas of the reservoirs. Unlike the earlier phases of development, the current wells have complex trajectories and are hooked up via crowded subsea manifolds. Because oflimited availability of drilling centers, most of the new wells are extended reach with narrow drilling margins. The target reservoirs are relatively thinner, poorly developed, and more limited in extent and size compared to targets in the earlier phases, increasing inherent subsurface uncertainties. With an expected low case ultimate recovery per well of roughly 10–15 MMstb, and average deepwater well cost of +/- $40 million, the stakes were high and hence critical to get it right the first time. If net-sand is poor or short because of suboptimal landing or well placement in the reservoir, the well objective (recovery and rate) can easily be compromised and could require drilling a sidetrack with additional attendant cost. Longer exposure length of drain hole (reservoir section) was known to improve well production rates hence an essential component of the well plan. To address these challenges and ensure the wells achieve their objectives and deliver their economic value, a geosteering technology (Reservoir Mapping While Drilling tool—GeoSphere) was adopted for optimal landing above the target reservoir(s) and placement within the reservoir channel sands using the Multilayer Distance to Boundary technology (PeriScopeHD). The deployment of geosteering technology was considered to be a success in enabling better sand exposures of the wells in the target sections, thus achieving the well objectives. This paper discusses the implementation of geosteering technology and learnings from two case studies in the Bonga infill campaign.

The importance of communication between well pairs in deep water turbidite reservoirs, where water injection is the main reservoir drive mechanism cannot be overemphasized. Well costs continue to be on the rise and well redundancy due to lack of communication between injector-producer pair is undesirable. Compartmentalization within reservoirs - vertical, lateral or both is a common phenomenon, and its detection is increasingly becoming significant in reservoir characterization. Whereas the use of linear pressure trends to infer vertical connectivity or otherwise is very well established, well-to-well data evaluation is critical for assessing lateral connectivity. In this work, residual pressure (commonly known as excess pressure) plots have been employed to evaluate connectivity between vertically stacked reservoirs which are otherwise assumed to connected under static conditions. We have tried to incorporate all available data types, including well logs, PVT sample analysis and geochemical interpretations prior to drawing conclusions on the risk of compartmentalization for each case. We have evaluated formation pressures and gradients from wells and compared the results against the accuracy of the wireline formation tester (WFT) tool. The first set of reservoirs evaluated is from an Appraisal field where development wells are being planned. The results will be compared to the pre-production wells from the an Analogue fieldwhich has been producing for over five years now. This work will then try to establish whether the excess pressure plots from the Analogue field could have predicted some of the production observations that are seen today. And if so, comment on what an excess pressure threshold may be for this region. Both the Appraisal and Analogue fields lie the same block. For the Appraisal field, this study is useful as a means of assessing the risk of intra-reservoir compartmentalization and provide an opportunity to optimize future development plans.