This paper presents a case study from Onshore wells in Sharjah, UAE on investigating liquid loading in 5 multilateral gas wells having various trajectories ranging from toe-up, toe-down and hybrid openhole legs. These wells are subjected to wellhead pressure reduction to maximize production rates. The main objective of the study was to evaluate the production performance for different completion designs with respect to liquid loading onset and overall production assessment with declining reservoir pressure. Dynamic multiphase flow simulator was used to conduct this study to accurately capture the details of the multilaterals system and its complex trajectories. The first step involved validating the well model with reasonable history match between the simulation and actual production data. The validated model then was used as a basis for predicting the liquid loading onset point for a given reservoir pressure decline. Multiple cases were investigated to evaluate various completion options (i.e. with or without tubing) to determine how and when the liquid loading occurs at different laterals with varying lateral trajectory. This study has showed that in such complex multi-lateral wells, laterals load up at different points in time and reservoir pressures, being affected mainly by the geometry and orientation of lateral and the production contribution. Moreover, installing tubing in these wells had the opposite anticipated effect on liquid loading by accelerating the liquid loading onset in the laterals due to the imposed additional restriction. Generally, toe-down trajectory tends to have thicker liquid film and a potential for reduced flow contribution due to liquid accumulation at the toe. These wells have a fishbone openhole multilateral network with comingled flow in the vertical section. It is observed that production tubing in the vertical section provides friction that accelerates the onset of liquid loading and hence results in decreased production for wells operating in very low reservoir pressure range. Based on overall production assessment ‘no tubing’ scenario would be more beneficial. Further, the timing of implementation of the tubing restriction later in the field life can be selected based on dynamic simulations (also evaluating economic constraints vs production gain). Transient mechanistic flow model captures the liquid loading phenomena by film reversal which usually occurs before the critical rate limit based on droplet drag forces assessment. Further, liquid loading onset occurs in the laterals first rather than the tubing section which reduces the applicability of conventional nodal analysis tools. Evaluating liquid loading behaviour in such multilateral wells with proper dynamic simulation is critical for understanding the laterals behaviour and therefore optimizing the production performance to maximize the wells uptime and ultimately the overall gas recovery as well as optimal usage of CAPEX.

Sharjah National Oil Corporation (SNOC) currently operates 3 fractured carbonate mature gas-condensate fields with some 35 years of production history. Until recent years these fields were operated by leading International Oil Companies (IOCs) which utilised some of the then latest technologies, such as underbalanced coil tubing drilling in order to maximise the production rate. The reservoir development and management scheme, however, did not involve gas re-injection to maintain reservoir pressure above the dew point. This led to production by simply blowing-down the field. Since there was negligible aquifer support the reservoir pressure declined rapidly and the dew point pressure was reached within 3 years, resulting in condensate drop-out in the reservoir. It is estimated that more than half of the original condensate in place still remains in the reservoir, although more than 97% of the gas in place has already been produced and the reservoir pressure have declined to around 10% of initial pressure. In order to determine the location and quantity of condensate remaining in the field, dual porosity reservoir models were created with legacy data which replicated the naturally fractured reservoir. These models were history matched and gas injection simulation runs were performed in order to estimate the injection rates, reservoir pressure increase, field communication and potential for condensate re-vaporization and mobilisation theory at a variety of pressures. This theory was put to test and confirmed when SNOC recently performed a pilot gas injection project in one of its fields. A mixture of processed gas from the gas plant was injected and allowed to stabilise. The new mixture of injected and reservoir gas was reproduced to estimate the deliverability and ability of dry gas to vaporise the in-situ condensate. A fundamental challenge with SNOC was to determine the PVT property of the initial reservoir fluid from a surface recombined sample which made it extremely difficult to decipher the original fluid properties and history matching the reservoir model. Utilising the field for gas storage can help elevate the reservoir pressure and increase the vaporisation of condensate, however since the field is naturally fractured it is susceptible to the injected gas fingering into a producing well. SNOC now plans to continue the next phase of the project to mature the modelling work, evaluate various sources of injection gas, understand the project uncertainties and establish the conditions required for the ECR project to be economically viable. This paper discusses the challenges, observations and its conclusion through the pilot gas injection project and its impact on the decision making for large scale implementation of enhanced condensate recoveries in the Middle East. Maximizing field development objectives by combining various opportunities is the key to determining sustainability in the lower oil price environment. This paper demonstrates how new technology combined with large volumes of legacy data can provide the perfect platform to evaluate the potential for enhanced condensate recovery (ECR) projects and take informed decisions for operators.

Sharjah National Oil Company (SNOC) operates 3 fields Onshore Sharjah with 30+ years’ production history from over 50 gas condensate wells. The fields were produced historically under a blow down scheme resulting in significant condensate volumes being dropped. While these existing resources could be recovered through drilling additional wells apart from optimization opportunities in the current production regime, the most economical solution would be to verify if the existing well stock could be confirmed as having sufficient well integrity to safely allow the continued use of these wells thereby extending the field life through careful well and risk management. The Sajaa and Moyeveid gas fields feature a series of challenging production issues. These include varying hydrogen sulphide levels upto 500 ppm, surface cemented annuli, sustained casing pressures, carbon steel tubulars, known corrosion issues greater than 0.5 mm per year, carbon dioxide and water production, all from multi-lateral wells at extremely low reservoir pressures. SNOC developed a comprehensive risk ranking process that categorized the wells into low, medium and high risk using a wide range of available production data, well age and corrosion inhibition data. Further investigation included corrosion logging data acquired from 2 wells in 2015 providing indicative well status and validation of electromagnetic corrosion measurement technology. Although, it did not provide a comprehensive and in depth review for a representative wider range of wells. In order to provide a more deterministic status of the well stock, and optimizing the risk ranking process, 10 wells were selected to be investigated with a campaign of corrosion logging in 2016. However, it was important that the intervention program would have minimal production impact with a small footprint slick-line intervention unit that would utilize state of the art magnetic imaging technology to record and measure the status of the well tubulars. Additionally, HSE impact was reduced by restricting the operations to daylight working hours and minimizing the numbers of personnel exposed to the well-site. This paper summarizes the logging operations, analysis of the data collected, well tubular status & issues such as shallow surface corrosion and well correlation on a field basis. It also focuses on how this was integrated into the SNOC risk ranking model to allow continued production from the wells, while still maintaining the well integrity status that supported the company’s philosophy of managing risks ‘as low as reasonably practical’ (ALARP) maximizing recovery from a mature reservoir

The analysis of existing high-vacuum mechanical pumps with magnetic suspensions is carried out. The schemes and algorithms used for calculations for permanent magnetic suspensions (PMS) and active magnetic suspensions (AMS) are presented. Based on the results of the analysis, the relevance of the use of magnetic suspensions in high-vacuum mechanical pumps was evaluated, the development prospects of high-vacuum mechanical pumps with magnetic suspensions were noted.

Sajaa gas field is one of the oldest fields in the Northern Emirates operated by Sharjah National Oil Corporation (SNOC) where Petrofac currently holds accountability for the Sajaa asset operations until November 2015. Since 1982, this mature asset has experienced increasing gas recoveries with declining reservoir pressures subsequently leading to condensate banking and liquid loading problems. Many techniques had therefore been adopted including drilling of multilaterals, plant inlet compression and foamer, but the effects were short lived as the reservoir pressure declined further. This paper deals with the latest production enhancement technique involving field wellhead compressors applied on the asset to increase its deliverability and longevity.This project involves the installation of 12 Well head compressors which effectively aim to include the entire inlet from the field through these units. A total of 18,600 HP of compression has been introduced throughout the field with these fuel gas powered reciprocating compressors, including a primary separation unit on each skid. They have principally been able to reduce the flowing WHP to as low as 15 Psig associated with a reduction of DeltaP across the wellbore, thereby reducing the effect of liquid loading and aiding to an increase in the primary condensate and water recovery. The scope of this paper is the analysis of the Full field compression (FFC) project providing an overview of the installation methodology, performance of the wells and the incremental effect of the project which exceeded the forecasted gain, along with troubleshooting from a subsurface point of view. Finally using the Integrated Asset Model to link the subsurface performance to the surface gain and forecasting the increment of reserves associated with the FFC in a mature retrograde carbonate reservoir environment. An insight into the factors influencing the compressor performance and the optimization techniques employed during the 2 year long project is also presented.