Intelligent well technology use Inflow Control Devices (ICDs), Inflow Control Valves (ICVs), and measurement devices that provide opportunity for monitoring and control of production from different reservoirs from the same wellbore. The common value drivers for the deployment of intelligent wells include reduction in well count during field development; accelerated ultimate recovery (UR); and accelerated production. Efficient and accurate modelling is therefore critical for the realisation of the full benefits of intelligent wells in addition to other technologies like the use of geochemical finger printing. In this paper, a simple workflow for modelling the performance of intelligent wells is presented. This workflow identifies the limitation of current standalone PROSPER model and provides a window to easily match the model to actual well test results, providing multiple calibration points and ensuring full utilisation of the data made available by the intelligent well accessories like the permanent downhole guage and downhole flowmeter. The workflow has been applied to carryout nodal analysis of both oil and gas completions in the Niger Delta, Nigeria. The modelling workflow is divided into two (2) aspects – the inflow modeling, for each inflow zone, and the outflow modelling that captures the commingled production. The commngled outflow model is used to generate the lift table for the GAP model. The well deliverability and PQ curves are generated and plotted using the Openserver utility in IPM, which can be used also to view the performance of the model against validated well test results. Results of applying the workflow to two case studies in the Niger Delta were analysed. The model was used to predict the expected performance of the wells at different surface choke sizes and ICV settings. The model results (flow rate, flowing tubing head pressures, flowing bottomhole pressures) matched closely (with maximum of 10% deviation) with the actual measured results, confirming the accuracy of the recommended workflow.

A study was carried out to establish the performance of a dragon well, or a well that dramatically changes inclination, in a thin oil rim reservoir. A well was simulated using commercial nodal analysis software by segmenting the inflow in multiple sections in order to incorporate the changes in trajectory and intersections with various reservoir layers. This simulation considered the pressure losses along the well bore for the varying trajectory, calculated for individual well sections, layers and combined commingle productivity and pressure profile; and was used to evaluate the well performance for a range of reservoir conditions (depletion, gas-oil ratio and water cut changes). This paper describes the approach used and key observations obtained from the results. A "segmented" inflow simulation approach can be used to model a dragon well. The method can be applied for modelling wells with sinusoidal trajectories in thin oil reservoirs. The results can be used to guide well and reservoir modellers in the concept assessment of this type of wells in field development studies. The model calculates the segment, layer, and total inflow and pressure profile in a complex trajectory. For the field and reservoir characteristics considered, the simulation indicated that the dragon well can produce through a wide range of conditions, including gas and water break-through. Good initial productivity can be expected from the well, but deteriorates fast with increasing GOR and water cut. As expected, the drawdown is not uniform along the trajectory; hence a drawdown stabilization strategy was addressed for the subject well through the use of a smart well completion. There is limited industry experience on sinusoidal or dragon wells modelling hence the results of the paper should be of interest to production technologists and reservoir engineers. This documented methodology can also be extended to simulation of complex horizontal or multilateral wells.

Recent regulations and standards demand that there is a need for a systematic Well Integrity Management and control during the entire life cycle of a well. Availability of reliable Well Integrity data is fundamental to a proactive, efficient and transparent life cycle Well Integrity management. The use of low cost smart systems, processes, and incorporation of a number of API performance standards have been adopted and implemented by operators to ensure that their Assets are operated within their defined operating envelopes and meet the required performance standards and process safety requirements. The operate phase is the longest phase in the Well Integrity life cycle management and thus a critical phase that requires intelligent systems, experience and resources to maximize and optimize the life cycle value of the Asset. This phase can span decades and usually involves data acquisition, assurance and analysis For well integrity prediction. The key challenge for operators is the ability to maintain a comprehensive and reliable dataset for proactive Well Integrity management due to reasons ranging from resources to gaps in critical data as a result human error and legacy well issues. This paper will discuss the Well Integrity data quality gaps, key challenges, data management architecture framework, improvement initiatives, lessons learnt and the impact in the overall Well Integrity Compliance.

Sand face completions have a major impact on a well's deliverability, by determining its productivity or injectvity throughout its expected life. In the Niger Delta, most reservoirs are shallow (below 10,000 ftss) and poorly consolidated, sand control forms an important part of sand face completion design. Sand management strategy involves using a software FIST (Fully Integrated Sand Prediction Tool) to carry out sand failure prediction analysis. In cases where sand failure is imminent, a sand control selection guide is used to determine the optimal sand control method to be installed. The selection is benchmarked against the performance of existing sand controls designs in analogue wells the in the region. A number of sand control mechanisms have been successfully deployed in various completions across Niger Delta which includes Chemical Sand Consolidation, Gravel Packs (Internal/External), Slotted liners, Expandable Sand Screens (ESS), etc. The complexity of deployment varies widely from the most complex multiple IGP/EGP to slotted liners. In all, most of the methods have exhibited good sand control properties however, with varied productivity. The ESS has presented a good balance between ease of deployment, productivity and life cycle management of the well. A field in the greater Gbaran area of the Niger Delta is proposed to be developed by three gas wells targeting three reservoirs. The reservoirs are unconsolidated and below 10,000 ftss, with Sonic log transit times in the range of 93 - 162 μsec/ft. Sand failure prediction on these three reservoirs using FIST indicated a high failure probability (95 – 100%) during the production life, thus requiring sand control. Following the process of selection, and Cased-Hole ESS was proposed. Although cheaper and easier to install with better productivity, a proper evaluation of the erosion tendency especially in Cased-Hole application of ESS in gas wells is essential to ensure full life cycle coverage. This paper documents the results of the evaluations carried out, optimization methods employed to evaluate the proposed sand control mechanism.

Smart well technology allows production acceleration from multiple completions and value realization from otherwise marginal reservoirs. Critical to the success of a smart well completion targeting more than one reservoir is the proper design selection and reservoir isolation to prevent cross flow. This case study describes the selection of a suitable gas well design from different available options, the considerations made in the design selection which incorporated the different completion components, one of the components being the feed-through swell packers which is its first use in the company, to achieve reservoir isolation. The paper also describes the execution of the selected completion design in one of the cases, as well as the testing of the well to verify reservoir isolation, and confirm the effectiveness of the feed-through swell packer. The selected completion design was cost effective, reduced operational / deployment risks (compared to other isolation options) and had no adverse impact on well productivity of the wells. It also achieved the objective of accelerating the recovery of a combined volume of 221 Bscf of gas from marginal gas reservoirs in a field.