Added Value of a Multiphase Flowmeter in Exploration Well Testing
- E.A. Mus (TotalFinaElf E&P Angola) | E.D. Toskey (Schlumberger Oilfield Services) | S.J.F. Bascoul (TotalFinaElf E&P Angola) | R.J. Norris (TotalFinaElf E&P Angola)
- Document ID
- Society of Petroleum Engineers
- SPE Production & Facilities
- Publication Date
- November 2002
- Document Type
- Journal Paper
- 197 - 203
- 2002. Society of Petroleum Engineers
- 5.3.1 Flow in Porous Media, 5.4.2 Gas Injection Methods, 3.1.6 Gas Lift, 3 Production and Well Operations, 4.6 Natural Gas, 4.2.4 Risers, 1.10 Drilling Equipment, 5.1.2 Faults and Fracture Characterisation, 5.1.5 Geologic Modeling, 2.7.1 Completion Fluids, 5.3.4 Integration of geomechanics in models, 3.3 Well & Reservoir Surveillance and Monitoring, 5.6.3 Pressure Transient Testing, 4.1.5 Processing Equipment, 2.4.3 Sand/Solids Control, 1.11 Drilling Fluids and Materials, 4.4.3 Mutiphase Measurement, 4.2 Pipelines, Flowlines and Risers, 2 Well Completion, 7.2.3 Decision-making Processes, 4.1.2 Separation and Treating, 5.3.2 Multiphase Flow, 5.6.4 Drillstem/Well Testing, 5.2.1 Phase Behavior and PVT Measurements
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A multiphase flowmeter was used in addition to conventional surface well-test equipment during five deep offshore exploration drillstem tests. Several immediate benefits were derived. The cleanup phase was monitored, which improved control of the formation drawdown as well as the prediction of well eruption. The flow history was better quantified, which improved the pressure-transient analysis. The instantaneous flow-rate measurements shortened flow periods and accelerated the decision process, reducing the overall test duration. In general, the multiphase flowmeter enhanced operation flexibility, confidence in the information acquired, and accuracy of the results.
There are three distinct processes occurring in a surface well test. Well fluids must be controlled, measured, and disposed. The objective of a well test is measurements, and the operational requirements to obtain those are fluid control and disposal. A successful well test requires an effective interaction of the measurement with the fluid control and disposal.
In exploration well testing, little is known in advance about how a well will perform. Exploration well-testing procedures and equipment are, therefore, designed to handle a broad spectrum of eventualities. Nevertheless, there are uncertainties that must be resolved during the well test to effectively control the well, to obtain representative well-test data, and to efficiently dispose of the fluid.
Deciding how and when to proceed with the well-test program requires information about how the well performs relative to the conditions. For example, the main flow period might not commence until nearly all the nonreservoir fluid is removed from the well and the formation's test interval. This requires a complete record of oil and water recovery volumes. This information is not complete with conventional well testing methods. Thus, in the absence of some information, a successful test can rely considerably on the judgment of an experienced well-test operator
Conventional Well Testing.
In a conventional well test, sufficiently determining accurate gas, oil, and water flow rates can be a challenge. Some common problems are poor fluid separation, flow instability, and poor meter calibration. Furthermore, with a large vessel to separate the fluid phases, flow measurements lack the resolution to identify small flow events or transient behavior. Fluid-level instability caused by control-valve oscillation or floating- vessel heave can also distort the measurement. With all the process equipment needed to separate the phases, the maximum well potential sometimes can not be obtained because of excessive backpressure imposed on the well.
Although critical to exploration testing, well production is not even measured before the well stream is cleaned up. Among the numerous challenges this causes, the buildup analysis of an early shut-in can be affected by the assumptions made for the flowrate history.
The sum of these challenges can cause misinterpretation in well performance and flawed execution of the well test. At the end of the test, the reliability of the results may be in question, and the analysis of the test may be misleading.
Multiphase Well Testing.
Multiphase flow measurements have been proven valuable in several applications of reservoir development and production well testing.1-4 The multiphase flowmeter adds considerable value in an exploration well test because it provides the heretofore missing information about well performance.
The fluid recovery rates and volumes of each phase (gas, oil, and water) are measured by the multiphase flowmeter without separating the phases. A simple flow-through device without moving parts, the multiphase flowmeter provides more accurate measurements that are free from the multiple error sources affecting separator measurements. More importantly, the measurement is achieved in highly transient conditions and without the imposition of any buffering or significant backpressure. This provides complete coverage of flow-rate data throughout the test. The multiphase flow-rate measurement is the first true representation of well production.
In benign conditions, multiphase flow-rate measurements permit the well test to be conducted knowledgeably and confidently. In more challenging conditions, it makes the difference between good data and no data at all.
Detail of the Operations
The operations described later pertain to exploration of deep offshore Angola. Before introducing mobile multiphase flow-measurement services, exploration wells were tested in a conventional manner with a typical well-test service package. Repeated problems with some of the flow-rate data acquired during the tests led to the addition of a multiphase flowmeter to the surface process layout. After a successful first test, the meter remained in the test program for each subsequent well test. Five drillstem tests (DSTs) conducted on four offshore wells are discussed in the following sections.
Defining the Need.
In several preceding exploration well tests, emulsion and/or foaming was a problem during high-rate flow periods. These conditions affected the quality of the flow-rate data measured at the separator because the emulsion and foaming could not be satisfactorily broken by the conventional methods of heat treatment, chemical injection, and gravity separation. In the deepwater environment, the riser cooling effect exacerbated the need for heating at the surface. It was impractical to supply the quantity of heat required. As a result, the flow rates were unreliable, which prevented a good analysis of the potential of these wells.
It has been shown5 that a compact combination of a Venturi meter and a dual-energy composition meter located at the Venturi throat can measure the flow rates of three-phase flow independently of the inlet flow regime. This was verified in several flow loops and field tests over an extensive range of flow conditions during a 3-year study period.5 This type of multiphase flowmeter would not be affected by an emulsion or a foam and would be able to deliver correct gas, oil, and water flow rates. It has been reported that a cross-correlation-type multiphase flowmeter is not best suited to this kind of mobile application because of the possible flow-regime dependence of the velocity measurement.5
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