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Encountering a reservoir in either a gas-down-to (GDT) or an oil-up-to (OUT) situation poses a challenge to development planning and reservoir management. The resulting uncertainties in the distribution, in-place and recoverable volumes of oil and gas may jeopardize expeditious execution of the field development project. To confirm the presence or absence of either oil or gas and establish a possible gas-oil-contact (GOC), in some cases the drilling of an appraisal wells(s) may be required. This paper describes a method that does not depend on dedicated appraisal wells to reduce GOC uncertainties and proves to be a valuable method to de-risk planned reservoir developments. Where credible pressure-volume-temperature (PVT) data are available from the subject reservoir, compositional-grading simulations (CGS) can be employed to evaluate the presence (or otherwise) of a GOC within a vertically continuous reservoir column. From a thermodynamic standpoint, the GOC is that depth at which the reservoir fluid transits from being gas-like to oil-like, and vice-versa. Considering some saturated and undersaturated oil reservoirs in the Niger Delta as case studies, this paper demonstrates the applicability of a combination of PVT and CGS to de-risk the presence of GOC without resorting to either a new well or a pilot hole. In the cases where well logs have established GOC, blind tests show excellent agreement between CGS results and well logs. Similarly, CGS accurately suggests the absence of gas-like fluids within the proven undersaturated oil reservoirs examined. Finally, the results of this study will document that CGS is reliable and cost-effective for reducing GOC uncertainties and de-risking field development projects. Consequently, this method is recommended whenever credible PVT data are available.

Unstable well flow is detrimental to the technical and economic performances of an integrated production system. To mitigate this problem, it is imperative to understand the stability limits and predict the onset of unstable production of an oil well. Taking advantage of the phenomenon of slug flow and the onset of unstable equilibrium from inflow performance and vertical lift curves of a producing well, this paper presents a new method for evaluating the stability of an oil production well on the one hand and estimating its stable production limits in terms of wellhead flowing pressure and flow rate on the other hand. A novelty of this work is the introduction and quantitative characterization of three distinct stability phases in the performance of a production well. These phases are uniquely identified as stable, transition and unstable flows. Practical examples and field cases demonstrate the robustness of the new method. When compared against results from a commercial wellbore simulator for the same set of problems, the new method yields an average absolute deviation of 5.3%. Additional validation tests against a common, but more computationally demanding method of stability analysis yield satisfactory results. Several parametric tests conducted with the proposed model and method provide additional insights into some of the major factors that control well stability, highlighting scope for production optimization in practice. Overall, this work should find applications in the design and management of production wells.

Produced water is naturally occurring water that is produced as a byproduct during the exploration and production of oil and natural gas from the subsurface system. Produced water brought to the surface contains high saline content and may also contain Naturally Occurring Radioactive Material (NORM). Therefore, the efficient treatment, use, and disposal of produced water remain a critical issue for the energy industry with environmental and human health implications. Over the years, researchers have presented numerous treatment technologies ranging from physical, chemical, and biological perspectives. Some industries have combined one or two of these methods to improve the treatment quality of produced water required for distinct purposes, and these practices have been extended to the energy industry. As the energy industry strives to sustain production capacities and maintain or increase profitability in this energy-transition era, water production is also rising while there is a reduction in its re-purposing and utilization for energy and environmental industries. Our study focuses on over 100 studies conducted over the past five decades. This study presents a comprehensive overview of the produced treatment methods, challenges regarding the execution and implementation of these methods in the energy industry. We highlight the important fundamental questions that are yet to be addressed and propose new directions for more environmentally friendly and economically viable solutions for the treatment and use of produced water.

Although gas-lift is an established technology for improving the performances of oil production wells, the simplicity, robustness and accuracy of gas-lift models remain to be fully resolved. As an improvement on the traditional practice, this paper proposes a new approach for modelling the performance of gas-lifted wells at steady-state conditions. The conceptual framework splits the wellbore into two segments. The segments are of unique characteristics, yet they are hydraulically connected. While one segment is controlled primarily by the upstream reservoir-sandface conditions, the dynamics of the second segment are dominated by the lift-gas. This work results in a new four-phase model and an accompanying workflow for analysing the steady-state performance of a gas-lifted well. Using examples from fields operating under diverse conditions in the Niger Delta and North Sea, the new model is validated against a commercial wellbore performance simulator and actual field results. The new model yields average absolute deviation (AAD) of 2.7 and 5.4% against the commercial simulator and field results, respectively. Notwithstanding its relative simplicity, the range of AAD recorded for the new model and workflow attests to its robustness and applicability in practice. In addition to its simple mathematical form, a competitive feature of the proposed model relative to the commercial simulator and most other models is that it accounts for the four phases (gas, oil, water and solid particulates) typically encountered in mature oil production wells and brown fields.