Permanent Downhole Gauges (PDG) can play great roles in production optimization as well as reservoir continuous monitoring and management. Data obtained from these gauges or sensors can give useful information to applications, including but not limited to monitoring artificial lift performance, pressure monitoring, transient well testing, and evaluation of well performance. Reservoir continuous monitoring, production losses mitigation, pump optimization and benefits from detection or prevention to early failure have been considered overcoming short-term concerns about cost containment during economic downturn. This paper presents case studies based on a pilot project deployed by Agiba Petroleum Company and Schlumberger in Aghar-4 field, Western Desert, Egypt. This field consists of three producers that are equipped with permanent downhole gauge and integrated real time system connecting bottom hole sensor technology to some essential surface measurement capability. Aghar-4 is a promising heavy oil field with a total of 13 wells drilled and being produced by sucker rod pumping to the date of the study. Aghar 4-1 was commissioned in January 2009 and is the first well in the Middle East operating with the intelligent downhole monitoring system application. This success story in Aghar 4-1 implied the installation of two more systems in Aghar 4-4 and Aghar 4-12. Later in October 2009, Aghar 4-12 made its history as the first world sucker rod well integrating downhole sensor, surface controller, and real time PC web-based satellite transmitted interface monitoring system. Artificial lift downhole equipment failures often occur within a relatively short period causing reduced or deferred production. Continuous real time monitoring of the environment in and around pumps will significantly improve production through a proactive surveillance and optimization of artificial lift operations.
Mature fields have the potential to contribute significantly to future reserves provided that the recovery can be optimized. The main objective of this paper is to discuss the application of some techniques and technologies to optimize the production in Ashrafi Field offshore, Gulf of Suez (GOS), Egypt. Ashrafi Field, located in south-western part of the Gulf of Suez was discovered in 1987 and put in production in 1992 from its Main Area. In 1997, the South-West Area, discovered one year before, started contributing significantly to the overall field production. The field consists of sedimentary reservoir units partially overlying a tilted block of fractured Basement reservoir. The field reached its peak production of 25,800 BOPD in June 2000 from 12 naturally flowing wells and then the production declined drastically. The only artificial lift type that was suitable for the field was the gas lift system and it was implemented starting 2004 in 80% of the wells. The strategy to unlock the unexploited potential in the field was to search for the bypassed oil through cutting edge technologies, using special techniques for stimulation of fracture Basement reservoir, combating scale and paraffin depositions in an efficient and economical manner. The final result for the use of such techniques and technologies was the increase of the oil production to more than 225 % of its levels before the intervention campaign, the increase of the gas production needed for gas lift system feeding and the decrease of the amount of produced water.
2018 will be the brightest year for upstream investment since 2014. Costs reduction and the oil price stabilization gives operators confidence in launching new challenging projects. However, launching new projects is still particularly challenging for deep-water assets. Even if project costs are 20% lower than mid-2014, deep-water projects are not yet competitive with tight oil, considering also the higher associated uncertainty. The direction to improve is clear: further cost cuts, through leaner development principles and improved well designs. Moreover, operators have to take advantage from lesson learned of projects already in production. Eni has consolidated on its West Africa deep-water assets a workflow that can support challenging projects FID through: Reduction of time to market parallelizing project phasesManagement of project uncertainty through flexibilityWork in integrated teams taking advantage from digital transformation More in details, the first target is to reduce time to market anticipating free cash flow generation. This is achieved through an appraisal while developing phase: drilling appraisal as first wells of development campaign, derisking the following well locations. Time-to-market reduction is achieved by parallelizing development phases, starting development plan definition during exploration phases and anticipating procurement of long lead items. This is possible if subsurface uncertainty has been properly defined through robust 3D models and if projects can guarantee the flexibility to capture new opportunities: fine tune well locations during drilling campaign, keep spare slots availability and sidetrack opportunities, substitute water and gas injectors with water alternate gas wells (WAG). In addition, Digital Transformation offers more and more the possibility to continuously update 3D models thanks to the availability of real time data, run thousands of simulations on super computers and monitor in real time field performance, taking advantage from simple daily operations. This work is aimed to describe the steps that were the key successful factors of Eni operated deep water projects in West Africa. The presented workflow can now be considered a standard approach for the most challenging Eni's projects and supported the company to reach record time-to-market for the execution of challenging deep-water projects in the range of 2,5 to 4 years from authorization to first oil.
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