Well performance management is a critical aspect of production system optimisation in an oil and gas field. Accurately defining the well operating envelope will not only ensure asset integrity, but will also ensure realistic production performance expectations (forecasts) from available well resource. This paper discusses an approach to defining well operating envelopes that incorporates the technical limits and constraints of the various components of the producing well (i.e. reservoirs, sand face completions, tubing erosion and surface production facility, etc.). The methodology employs a visualization tool to graphically represent the operating envelope for the wells based on these constraints. This approach has been implemented in several fields and wells in Shell Nigeria with varying completion types and field-wide constraints. It has also been proven to be flexible enough to accommodate the possible variations between well types and field peculiarities. The case study of five fields in SPDC Swamp West Asset presented in this paper will demonstrate this flexibility. Some of the benefits realized include improved reservoir management and water cut control. Furthermore, the visualization tool has been used to carry out exception based well surveillance that has proven to improve our response time to well deviations for better deferment management.

MOT reservoir has a unique case of uncertainties as a result of data paucity being in a field where no production has occurred, and there is need to reduce the uncertainties associated with the key evaluation parameters required for making investment decisions. This paper presents how a multidisciplinary team resource was leveraged on in managing the identified uncertainties to deliver a robust development plan for the reservoir of interest. The approach deployed emphasize on integration and collaborative interpretations from the constituting disciplines in the study team. Early focus was placed on uncertainty identification, quantification and management. Iterative efforts were necessary to achieve consistency of results and preservation of physical meaning as the study moves from one domain to another. A consistent framework for quantifying the respective impacts of the identified uncertainties was developed, and realizations were constrained by the most impacting parameters to generate a probable representation of the subsurface. Subsurface development concepts were tested and suitably selected to optimize recovery using the base case realization as a control, and preliminary economic evaluations were also performed to determine the project robustness to risk and the magnitude of the investment. The experience from this work provides a reliable approach to handling the development of a green field reservoir with limited data availability. An approach to overcoming several limitations on how to predict a fit-for-purpose PVT-table, developing a representative SHM were also presented, and the success obtained further emphasize the advantage of integration in a multidisciplinary team. The results showed that the high impacting uncertainties were structure, fluid contacts, and relative permeability, and the identified uncertainties were managed by building realizations to adequately capture the possible outcomes, and the preliminary project economic evaluations suggests that the project would be viable even for the Low-Case outcomes, hence adding value to the company portfolio.

The importance of multi-discipline integration in the various phases of hydrocarbon exploitation cannot be over-emphasized. In the past, the various subsurface disciplines, within the oil and gas industry, worked in silo-like organizations which often results in a sub-optimal understanding/evaluation of the subsurface data. However, in recent times, much has been done and written on multi-disciplinary integration and its benefits particularly with respect to subsurface studies. The Zed field, which is the subject of this paper, is a predominantly gas bearing partially appraised field. The field is composed of a series of stacked sandstone reservoirs located in the Niger-Delta Region of Nigeria. Given the limited subsurface data available within the hydrocarbon-bearing areas of the field (only 2 of the 6 wells in the field penetrated the hydrocarbon-bearing sections), one of the biggest challenges of developing this field remain the high level of subsurface uncertainties coupled with the potentially low economic value of further appraisal and development of the field. In order to adequately assess these uncertainties and the economic feasibility of developing the Zed field, a detailed subsurface study involving a full re-evaluation of all potential hydrocarbon bearing sands penetrated by the wells was required. The study, which kicked off with a comprehensive integrated multi-discipline data review and quicklook evaluation, resulted in the identification of two additional reservoirs previously considered too marginal to contain substantial hydrocarbon. This paper details how the systematic, multi-discipline data integration and review of these two reservoirs helped in the identification and determination of higher hydrocarbon volumes in these reservoirs; and how this has helped in improving the economic value of the Zed field development project.

This paper presents the results of a 3D model constructed for a giant, densely faulted reservoir in one of the biggest fields in the Niger Delta. The study also showcases how simple analytical techniques applied in a technically thorough manner can achieve close or similar results to those from a calibrated 3D simulation model. In carrying out this work, a detailed 3D model was built and calibrated for a very mature reservoir; incorporating results of the recently drilled wells in the field, revalidated integrated data and latest historical performance data. The reservoir, which is densely faulted by a conjugate system of synthetic and antithetic faults, is the largest in the field accounting for almost half of the field's resource volumes. The large number of NW-SE faults, coupled with the relatively high offtake rates from the reservoir, have throttled the activity of the otherwise infinite aquifer and led to severe pressure depletion in the reservoir. Consequently, a lot of the producers quit at relatively low water cuts (~40 − 50%). One of the objectives of the detailed modelling study was to investigate the benefits and gains of gaslifting existing and future new wells. Prior to this study, simple decline curve analysis (DCA) had been carried out independently on a well-by-well basis using estimated abandonment conditions under gasliftassisted flow to predict the recoveries and gains from gaslifting. The prediction results from the full-field calibrated model compare very closely with the estimates from the individual wells DCA's and suggest that the DCA results can be used as 50/50 estimates for other reservoirs in the field where there are no full 3D models. This work therefore supports the fact that simple analytical methods, which are applied in a technically thorough manner, can still be used in the absence of full 3D models.

In recent years, numerical reservoir simulation (3-dimensional modelling) has become a very useful optimisation tool, not just for field development planning but also for ongoing reservoir management. Although several analytical methods (such as material balance equations, Buckley-Leverett displacement theory etc) are used as computationally fast and inexpensive tools, they have been recognised as being incapable of capturing the details and complexity of certain reservoirs and processes. The field presented in this paper is one of the biggest oil fields in the Niger Delta, with an estimated oil in place of over 2.5 billion barrels and cumulative oil production close to 1 billion barrels. About half of this volume and production come from a single reservoir, which is densely faulted. The large number of intra-reservoir faults and the relatively high offtake rates have inhibited the activity of the otherwise strong aquifer and resulted in the high pressure decline observed in this reservoir. Consequently, a lot of the wells quit at relatively low water cuts of 40-50%, with the reservoir pressure being insufficient to lift the crude to surface at higher water cuts. One of the recommendations of the FDP Update was to increase oil recovery through fieldwide installation of gaslift. However, to quantify the gains of gaslifting and optimize oil recovery through effective reservoir management, an integrated detailed 3D model was required due to the structural complexity of the reservoir. This paper presents the workflow used in constructing, initializing and history-matching the 3D reservoir model; and how the history-matched model was used to assess different development scenarios for improving recovery from this large mature reservoir.