D1 is an oil and gas field located offshore of Bintulu, Sarawak. It's a hub with several tie-in fields namely, D1-A, D1-B, D1-C, D2, D3, E1 and J1. Over the years, as more fields were tied-in to this hub, there have been significant increase in both oil and gas production. D1's facilities were designed to cater for high liquid flowrate. Hence, there was no need for a major topside modification to cater for increase in liquid production. However, with increasing associated gas (AG) produced from all these tie-in fields, a serious topside constraint arose concerning associated gas due to insufficient compressor ullage. Consequently, the excess gas which cannot be compressed had to be flared resulting in higher flaring/venting (FV) than the limit set by the host government authority. In order to avoid any FV violation, the field's operator had to increase the operating pressure of the low and high pressure (LP and HP) separators to reduce the amount of gas that was being flared. This paper describes the topside optimization that was diligently conducted over a period of 7 months to test and achieve an optimum production while maintaining FV within limits. Implementation of this effort involved process study to evaluate the compressor ullage availability verus current and future gas production from the hub. Based on this info, the operating philosophy of the existing 2 compressor trains at D1 were changed from 2 x100% to 2 x 50% in which both trains were put online concurrently instead of 1 unit running and 1 unit on standby. This new operating philosophy required changes to the compression system and re-strategizing the maintenance and spare parts management for both units to ensure sustainable operation over the long run. This zero-cost optimization revolves around 3 key performance indicators. Firstly, the excess gas that was previously flared can now be compressed and exported contributing to more than 100% increase in gas sales. Secondly, in line with the hub's efforts to reduce its carbon footprint, flare reduction of almost 50% was achieved. Finally, from subsurface perspective, running 2 compressor trains reduces the operating pressure of LP and HP separators by 1.5 barg and 2.5 barg respectively resulting in a significant reduction in backpressure to the wells. This improved oil recovery from wells across all the fields tied-in to D1 hub.
Commissioned in 2008, J field operates as an unmanned satellite platform that sends its hydrocarbon to an existing D complex 50km away via a full well stream (FWS) subsea pipeline. Sustaining production became challenging as reservoir pressure started depleting. Besides that, due to gas break through, high gas-oil-ratio (HGOR) wells were closed-in as the gas from these high pressure (HP) wells was exerting backpressure to the low pressure (LP) wells when they commingle at the production manifold. To address this surface constraint, a well-to-well (WTW) gaslift system was introduced in 2016 by utilizing the gas from HGOR wells as the gas lift (GL) supplier to LP wells. This initiative proved to be a success as the overall liquid production from J increased by 20% resulting from revival of idle LP wells, improved recovery from existing LP wells and re-activation of HGOR wells. After 3 years of commissioning, the reservoir pressure from the initial GL supply wells started depleting and unable to cater for the gradual increase in gaslift demand by the LP wells. This setback caused an unplanned deferment of ~1.0 kbod to the LP wells. To avoid prolong production interruption, the team successfully identified a new virgin gas zone in one of the existing well at J8. However, converting this LP well into a HP/gaslift supply well required both subsurface intervention as well as surface modification. Hence, this paper discusses the methodology applied to overcome the constraints via an integrated approach from various disciplines resulting in a significant value creation through production sustenance contributing to increase in J's field production life.
Software offshore outsourcing is strong pillar of software development. Software offshore outsourcing involves many risks, due to internal or external factors, that must be recognized and managed. Each organization that deals with the offshore outsourcing must be well aware of all the risk factors and barriers in the offshore outsourcing to maintain the quality of their product. It is very important for the Pakistan's software industry to improve and maintain the quality of the products with minimal risk and compete with other countries in offshore outsourcing. The problem addressed in this research article is to minimize the risks occurring in offshore software outsourcing. For that purpose, we propose some offshore outsourcing risk mitigation guidelines for the software industry of Pakistan. We use empirical analysis and the qualitative method. A comprehensive literature review is carried out. The risk factors related to offshore outsourcing specifically for Pakistan's software industry are generated empirically.
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