The advent of high crude oil prices and mature fields has seen a rush for efficient recovery methods. This has spurred the development of "monitor-feedback-control" systems through intelligent well system (IWS) and interventional processes. Traditionally, downhole permanent flow measurement is performed using differential pressure meters; e.g. venturi. The intrusive nature of these flowmeters prevents easy access for interventional processes and creates a loss in well lift. The main aim of an inverted venturi design is to allow full bore access whilst maintaining the downhole measurement accuracy requirements. The flowmeter has a reverse mechanical design compared to a restrictive venturi. Instead of a constricted section in the tubing, the inverted venturi has an expanded section. The theoretical principles are still based around simple energy and momentum conservation. Due to these facts, the operation of the tool requires the use of a pair of high resolution pressure gauge. The main breakthrough came from the development of a high resolution pressure transducer. Surface testing of the flowmeter has demonstrated flow measurement uncertainty better than 8% for instantaneous flow rate measurement and better than 1.5% in bulk flow rate measurement. These flowmeters have also been deployed successfully in the field. Installation of these flowmeters in the Gulf of Mexico (GOM) region has shown a similar level of accuracies and has provided immense value to production. Apart from providing full bore access, the flowmeter is more robust as it is able to withstand higher gas volume presence in production rather than that of restrictive venturi. Due to the sensitivity of the pressure transducer, the flowmeter is also able to detect the presence of gas in production which adds value to the recovery process. Installations are planned in the near future in IWS applications. These will include applications for multi-zone allocation flowmeters, injection flowmeters for both gas and water applications and commingled flow production meters. The application for the inverted venturi is limitless as it is not constrained by the typically issues surrounding restrictive venturi such as the loss of wellbore access and well lift. Introduction Over the years, the oil and gas community has had its share of scare mongering concerning declining reserves. This has triggered a hunt for more efficient technologies both in the drilling and exploration as well as completion and production. The development of more complex recovery technologies is aimed at prolonging the recovery period from mature and brown fields. These improvements include the introduction of intelligent or smart well technology [1]. Intelligent technology aims to utilise the feedback loops system (figure 1), whereby production is monitored and the information is fed back to aid in decision making for interventional processes to take place. Using downhole control tools, production can be adjusted to modify the rates, fluid types and fluid composition. Other interventional processes include more invasive procedures, e.g. re-perforation. There are two feedback loops used in production optimisation; the fast loop and the slow loop as described in the paper by Going et al. [2] and Vachon et al. [3]. The fast loop is a production optimization loop whilst the slow loop is also known as a reservoir optimization loop - intended to prolong production from a particular well or field. The monitoring component of the loop is achieved through the usage of permanent downhole monitoring tools. Permanent downhole monitoring equipment is defined as the tools that are placed downhole for the lifetime of the well with little or no need for intervention (e.g. servicing). These tools include pressure and temperature gauges, flow meters, fluid fraction meters, fluid composition meters, seismic and microseismic tools and any auxillary equipment required to communicate data to surface.
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.
In the current climate of production monitoring, the main concern is to obtain measurement that has high accuracy and specificity. This can be achieved using a system that is independent of flow regime, having the ability to differentiate the velocity and mass flowrates of at least three phases; gas, oil and water. In addition, it should be capable of quantifying the volume fraction of each phase with respect to the overall flow volume. Currently, there is no single flowmeter that can reliably perform these tasks. The design of an in-well flowmeter has to account for the electronic components susceptibility to high pressure (P) and temperature (T) by equipping the system with PT sensors. By monitoring the environment, the pressure and temperature are maintained below pre-defined thresholds. This ensures a higher level of accuracy in the measurements as well as prolonging instrument lifetime. The principle of flow measurement adopted is based on nuclear magnetic resonance (NMR). NMR is suited to flow evaluation in this industry due to the fluids present, i.e. water and hydrocarbon (gas or liquid). These fluids contain 1H and 13C nuclei which are important to NMR measurements. Unlike conventional flowmeters which measure the physical characteristics of the fluid, NMR monitors the molecular environment of the fluid. NMR has the ability to distinguish the different phases through the use of intrinsic molecular properties, i.e. relaxation times and resonant frequencies. In NMR, the volume fraction is calculated from the proton density. The flow measurement is obtained by monitoring the magnetised nuclei flow into a detection zone. The velocity distribution function is then calculated by applying an inverse algorithm to the data. The advantages of this system are its ability to be used as a single self-sufficient instrument and its phase independence for up to a two phase flow. This flow-independent measurement technique could be extended for use in three and four (solid) phase flow. Introduction There has been an increase in the application of nuclear magnetic resonance (NMR) in the oil and gas industry in the recent year. The first description of NMR was introduced independently by two scientists, Felix Bloch and Edward Carr Purcell, in 1946. Twenty five years later NMR was developed for use in the medical industry on both sides of the Atlantic by Sir Peter Mansfield in Nottingham, UK and Prof. Paul. C. Lauterbur in New York, USA. Henceforth, the application of NMR escalated in the medical field and it is still growing. Simultaneous, it was also being applied in the oil and gas industry but it has not gained such a widespread application. Primarily the use of NMR has been in the field of well-logging as established by Loren (1969), Loren and Robinson (1970) and Robinson et. al. (1972). This has developed further into commercial tools available today such as MagTrak™ by the BHI group, MRIL by NUMAR and CMR by Schlumberger. This utilises the intrinsic properties of the T2 relaxation time to determine the porosity and the permeability of the well. Flow measurement using NMR did not begin until the late 1950s when Singer et. al. developed a technique of measuring blood flow using NMR. More flow measurement applications were later introduced especially for industrial uses. The first commercial NMR flowmeter was produced in 1968 (Genthe et. al., 1968). However, the system gave velocity readings which were only valid in a laminar flow. It was not until 1983 that Krüger et. al. first developed and tested a method of measuring turbulent flow. This system provides velocity values whilst obtaining mass flow measurement in 2 phase flows. Though the development of NMR for flow measurement has been extensive in many of the process industry, there is little publication of flow measurement in the oil and gas industry (OGI). The most recent publication in 2002 outlines the use of NMR in water cut metering for a 2 phase mixture of bitumen and water (Wright et. al. 2002). However, this tool neither provides velocity nor flow rate information. As yet, there is no commercially available NMR flowmeter in the OGI, either as a subsurface or downhole application.
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