Several criteria and strategies have been developed to predict sand failures and to select appropriate sand control methods for improved completion designs and to maximise oil production at moderate unit technical cost. The depth criterion, SPADE equation, Rock Mechanic Equations incorporating Brinell Hardness Number and Unconfined Compressive Strength have been used extensively to predict sand production tendencies and to propose completion types. None of these criteria and strategies has explicitly incorporated the depositional environmental factor that defines the origin of these oil-bearing formations. A recent study aimed to correlate depo-belts and depositional environments to actual sand production using historical data of producing wells in the Niger Delta but covered only the Greater Ughelli depo-belt to some depths (SPE-163010). That study indicated a predominance of high sand producers in the channel sands depositional environment of the Greater Ughelli Depobelt. This paper therefore seeks to complete the investigation across all the remaining depo-belts and litho-facies and to share the review outcomes/ findings with the goal of establishing correlation between known rock mechanic principles and models used in sand failure prediction and sand control selection as a total system approach, providing wider solutions to sand control challenges in the oil industry.

Sand production in oil wells impairs full reservoir production capability, erodes sand face completions, down-hole tubular and surface equipment. The debilitating effects of sand production on surface production equipment are manifested in the plugging of flow lines, production manifolds and separators, leading to significant deferment in production due to downtime of facilities for sand clean out and component repair and replacement.2000 oil wells in the Niger Delta area have been reviewed to understand the sanding tendencies of the oil well completions and establish the completion strategy and practices that have successfully reduced sand production and its impact. It is observed that over 100 Mbopd oil is locked in as a result of produced sand. A plethora of sand control mechanisms such as Internal Gravel Packs, External Gravel Packs, Stand-Alone Screens, Premium Screens and Sand Consolidation Chemicals have been installed to reduce sand production in oil wells to acceptable rates but several cases of failures have been observed reviewing the past history of the oil wells.While several operators have developed guidelines to judge when sand control is required and how to operate the oil wells safely, there are still grey areas to be explored to understand the variation of formation consolidation indices from one Depo-Belt to another. The sand production performance of 2000 wells have been reviewed to examine whether the tendency for sanding can be attributed to oil well completion techniques or in-situ formation consolidation or a combination of both. It is also widely believed that formation burial depth can be used as a consolidation parameter to decide whether to include sand control in oil completion design or not.This paper seeks to share the results of the review of a large population of wells located and completed in different Depo-Belts in the Niger Delta with a view to helping operators streamline their decision-making process to include or not to include sand control systems in their oil wells for efficient production performance at less deferment due to sand production and lower completion and operating cost.

The M001 project involved the hook-up of 12 wells (17 conduits) which were drilled and completed between year 2000 and 2005 but were closed-in for operational reasons, until year 2019 when the first seven (7) conduits on cluster MX1 were cleaned up successfully. The seven conduits (Well-A, Well-B, Well-C, Well-D, Well-E, Well-F & Well-G) were expected to flow via three 8" bulk lines. Post well open-up and handover to production, significant bulking / backing out effects were observed. An average Flow Line Pressure (FLP) of ∼22 bar was recorded on the flowlines, hence limiting the capacity to bulk the wells, [FLP increases towards Flowing Tubing Head Pressure (FTHP) hence, pushing the well out of the critical flow envelope as FTHP<<1.7FLP]. Due to this challenge, total production from Cluster MX1 was sub-optimal with only five (5) conduits out of seven (7) able to flow due to bulking and backing out effect. The sub-optimal performance from the conduits were investigated using the Integrated Production System Model (IPSM) / PIPESIM models. Four different scenarios were run in the model and the calibrated IPSM model indicated all 7 conduits should flow if there are no surface restrictions. The model identified pressure, mass and rate imbalances in the integrated system and suggested the presence of a restriction at the manifold, causing sub-optimal production from the wells. The model outcome triggered an onsite investigation / troubleshooting from the wellhead to the manifold at the facilities end where an adjustable choke was identified in the ligaments of the manifold. In line with process safety requirements, a risk assessment was carried out and a Management of Change (MOC) raised to remove the adjustable choke at the manifold. Post implementation of the intervention, all the seven (7) conduits produced without any bulking effect. Total production realized from the seven (7) conduits post execution of the recommended action is ca. 9.3 kbopd against 5.2 kbopd pre-intervention. A total of ca. 4.1 kbopd production gain was realized and 10 mln USD proposed for additional bulkline was saved.

In the oil and gas business, a key strategy of well management is the deployment of the right tools and knowledge to enable continuous and optimized production. One of such tools is Matrix acidizing - A stimulation activity designed to remove wellbore damage and improve well inflow. The ability to sustain optimal production from most wells after acidization is often hampered with further fines migration problems and this requires specialized treatment to mitigate. WELL-001 quit production and was re-entered for a workover in 2018, to recomplete shallower on the same reservoir sand and restore production, however, post workover and subsequent clean up, the well failed to sustain flow. Two additional stimulation operations were also unsuccessful despite gas lift assistance. An Integrated review was held which identified key damage mechanisms impeding flow; deep fines migration which are not well handled by conventional stimulation recipes, emulsion and impairment from Loss Circulation Material (CaCO3 + XCD Polymer). A Novel solution was identified which included an Ultra-Thin Tackifying Agent (UTTA) as part of the stimulation cocktail with the primary purpose of stabilizing the fines at source and preventing further migration with the flowing fluids. The treatment was deployed successfully and the well lifted immediately, achieving a rate of 800 bopd vs a planned potential of 650 bopd. The impact of this success is not only evident in production but also in resource volume estimation and booking.