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The Agbami project offshore Nigeria uses a suite of production monitoring, control and optimization tools and techniques. The project uses an intelligent well completion whereby production and injection is optimized from the well through the relevant time feedback of information from downhole pressure, temperature gauges and flow meters. A downhole interval control valve provides the capability to control production and injection, thus maximizing the recovery of hydrocarbon from the field. The field consists of both injection and production wells. Oil production is from multiple zones, which are co-produced into the wellbore. Due to the complexities of the subsea production and injection manifold and riser configurations, downhole flow meters are used for production and injection allocation purposes for the different formations within the reservoir. Agbami Field utilizes an in-well flow meter. The technology is based on a differential pressure full bore electronic flow meter which is first in the industry. The sensors utilized are high resolution pressure and temperature sensors. In order to demonstrate the robustness and the capability of the flow meter for production and injection allocation purposes, a series of flow loop qualification testing have been designed. One of the tests used a mixture of oil and water in a test facility to demonstrate the capability of the flow meter to accurately measure oil and water production. This test is probably the first of its kind using a test structure over 100 ft in height. The paper will outline the aims, the preparation requirements, the conducted test and the resulting qualification testing. It will also demonstrate how the results will assist in the production allocation and optimization of recovery from the field. Through this testing, the operator demonstrated commitment to the intelligent well completion initiative as well as the provision of an accurate method of allocating production using in-well flow meter and pressure and temperature gauges. Introduction The Agbami project is located 70 miles offshore Nigeria in approximately 5,000 feet of water in the central Niger Delta. At $7 billion, this project in OML Block 127 and 128 is poised to be Nigeria's largest deepwater development. This field was discovered in 1996 when Texaco and Famfa were granted the rights to the 617,000 acre block 216 where the reserves were proven in 1998. Chevron is the operator, with a 68.15% interest; Statoil has an 18.85% interest (which it took in 2004) and the other 13% is held by Petrobras. The field is operated under the terms of two deepwater production-sharing contracts (PSC) and a technical sharing agreement (TSC) between Texaco and Famfa.

TX 75083-3836, U.S.A., fax 01-972-952-9435. AbstractEvaluating the productivity of a well through well testing is an essential aspect of managing production operations and reservoir recovery. When the reliability of gas, oil, and water flow rates is challenged by common events such as flow rates beyond the separator capacity or oil-water emulsions, the value of the well test can be severely diminished or even negative. Action taken or not taken as a result of an erroneous well test result can be counter to the production objectives and costly to the reservoir recovery. This paper documents the use of a mobile dual-energy multiphase venturi flowmeter to test high-pressure and highflow-rate wells in an offshore Nigeria field. Problematic fluid properties and challenging separation conditions limited the capabilities of the test separators to adequately measure the flow rates of the individual phases of the well effluent. Reliable rate measurements were hindered by the well's high pressure and high flow rates and by the presence of oil-water emulsion, which made phase separation extremely difficult.Examples of well tests performed with the flow meter demonstrate the benefits of robust measurement principles in these adverse conditions. The value of capturing the flow transients using a high-frequency dual-energy spectral gamma ray detector is also illustrated, as it allowed a better understanding of the behavior of fluid flow in the wellbore. The flowmeter data enabled production diagnostics. Based on the flowmeter information, recommendations to further investigate the sources of water entry into the wellbore were made.

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Intelligent field completions have seen more frequent deployment in the oil and gas industry in recent times. This is most likely due to the benefits that have been observed from real-time data acquisition, surveillance and optimization based on analysis of data gathered. With continuous acquisition of real-time data, analysis of the transient pressure and rate data can be used to understand changes in reservoir and well performance over time. The aim of this paper is to show how the evolution of parameters obtained from pressure transient analysis can be used to optimize well and reservoir performance. Key parameters obtained from pressure transient analysis (PTA) are permeability, skin, reservoir pressure and information on boundaries depending on shut-in duration. Analyses are performed for all shut-ins of the completion, both planned shut-ins and unplanned shut-ins (emergency shutdowns - ESDs). The results of all these analyses are catalogued to provide an historical surveillance data which, when trended, can provide insight into the near-wellbore performance of a completion as well as the reservoir. This paper demonstrates how Pressure Transient Analysis of real-time data was used in the Agbami Field to optimize production from the field. Two case studies are presented where analysis of transient pressure data was used to identify water injection front movement in a waterflooded reservoir and increasing near-wellbore damage due to fines migration. The results were used to optimize injection into a waterflooded reservoir to achieve a balance between maintaining reservoir pressure and optimizing voidage. In the case of continually increasing skin, the completion was stimulated with production increasing by a factor of 15.