Dual-energy spectral gamma ray / Venturi multiphase flowmeters present an efficient and cost-effective means of testing wells in many field applications. A simple, efficient and quick procedure optimizes the utilization of these types of multiphase flow meters for well testing. This paper presents the field operating procedures for installing and using multiphase flowmeter and gives practical recommendations for performing well tests with or without a reference, such as a separator. The analysis of 415 multiphase well tests performed worldwide has provided some insights into the accuracy achieved in the field and has led to some recommendations for the test design. The ability of a multiphase flowmeter to perform a measurement in the absence of a flowing reference is essential to well testing in most applications. Furthermore, the high mobility of the equipment (with up to three wells tested in three different locations per day) allows a very efficient and short turn around time for installation and operation. The parameters required to perform the setup of a meter fall into two categories: meter static empty pipe reference and fluid properties. A detailed review of each parameter is presented along with its sensitivities when determining the flow rates of oil, gas and water. A description of the field procedure used to determine each setup parameter is provided and a series of field examples are presented that illustrate the efficiency of using multiphase flowmeters for well testing. Introduction The use of multiphase flowmeters in well testing is not new. Early developments (in the 1980s) of multiphase flowmeters have been geared towards the testing of wells mostly in the United States. In the early 1990s, the engineering of multiphase flowmeters took a form more oriented towards pure instrumentation and metering applications, with many operating companies metering departments and research centers working in close collaboration with various suppliers to advance the technologies.1–18 Key technology breakthroughs, mostly in the determination of fractions combined with a better understanding of multiphase flow dynamics, have improved the overall confidence in the techniques and led several operators to implement field applications of multiphase flowmeters. Most of the meters deployed in the oil field to date are installed permanently in production systems. Such applications will not be discussed here. We will focus on the challenges of mobile well testing operations, supplied as a full service package by a service company. Review of benefits of multiphase flowmeters Traditionally well testing is performed using single-phase flowmeters installed on the oil, gas and water outlet of test separators. Large pressure vessels, important hydrocarbon inventory in piping and separator bodies, heavy lift, large rig-up and operating crews have been some of the chores attached to well testing. Refs. 16 and 19 illustrated the benefits of multiphase flowmeters over test separators in some field applications. Although some tradeoffs are inevitable, overall multiphase flowmeters bring an efficient solution to well testing measurements. Their main benefits are gains inSafetyLogisticsDuration of the operationData quality
New requirements have recently appeared for accurate and reliable flow rate measurements in various operational areas where viscous fluids are produced. Heavy oil as produced in Venezuela, Confederation of Independent States (CIS), Brazil, Angola and China and lighter oil emulsified with large water cuts (worldwide) present new challenges to multiphase metering. The compact, cost-effective multiphase meter described in this paper is intended to replace large, costly test separators designed for heavy oils. The meter is non-intrusive and combines a classical venturi to measure total mass flow rate and a dual energy gamma-ray composition meter to measure oil, water and gas fractions. A benefit of this compact design is that the meter can be switched from one well to another and provide robust, consistent flow rate measurements without any flow recalibration. According to published single-phase flow literature, liquid viscosity plays an important role in meter performance. Oil companies are becoming increasingly aware of these problems and want more evidence that a multiphase meter will perform regardless of fluid properties. To qualify the multiphase meter in high-viscosity flows, we conducted comprehensive flow loop tests in Venezuela. The challenge was to gain a solid understanding of viscosity effects even in the presence of large amounts of gas, and for the entire operating envelope of the meter. These test results have been used to refine the meter interpretation model to maintain the metering accuracy in these conditions. The interpretation includes a mixture viscosity model based on the dead-oil viscosity; for permanent monitoring and periodic testing, the effluent viscosity variations are updated when pressure, temperature or water cut is changing. To demonstrate that the specified measurement accuracy was achieved up to the highest viscosities tested (several thousand centipoise), the meter was field tested in comparison with a test separator. We present the results of 54 jobs. Until recently, the only multiphase meters available to measure viscous oil flowing with gas were intrusive. Positive displacement meters, such as oval gears, twin helical screws or vane types, were used to measure the total gas-liquid volume flow rate. These meters are very sensitive to severe slugging in the upstream pipeline and prone to mechanical damage from produced solid particles. The lightweight, small-footprint meter described here solves these problems. Consistent flow rate information can be obtained even when the meter is switched from well to well. Fluid property or flow regime changes do not affect the flow rate measurement. Introduction One of the main objectives of multiphase flow meter design is a low-cost system that will accurately measure the flow rates of oil, water and gas in difficult multiphase flow regimes. These include emulsions, high-viscosity oils and foaming conditions for which conventional metering systems based on phase separation have great difficulties or cannot successfully perform the tests. Even during efficient separation conditions in a conventional metering system, there is a significant advantage in continuously monitoring a well stream. Whereas a conventional testing system may take hours for stable measurements, a multiphase flow meter can yield good test results minutes after the well is opened. Elimination of a test separator, manifold and/or flow line is ordinarily the single most important reason for choosing to use a multiphase meter. Test separators and the associated metering equipment are expensive and require additional platform space on offshore topside installations. In satellite fields, a test line back to a test separator on a platform is a significant capital expense. For subsea applications the advantages are even greater as separate test lines and, in some cases, entire platforms, may be eliminated.
Scale deposition poses serious challenges to maintaining production and minimizing operating costs and it ranks high amongst the concerns of operators presenting a major threat to flow assurance, not least for remote subsea and satellite unmanned developments. A new methodology enabling the early detection, type identification, estimation of the thickness of the scale deposit and its rate of accumulation over time is presented using dual-energy spectral gamma ray / venturi multiphase flow meters. Several field examples of scale built-up are presented with detailed analysis showing the sometimes-surprising speed of deposition even at very low water cuts. The data from dualenergy spectral gamma ray / venturi multiphase flow meters was used to define the type of acid treatment required and to evaluate its efficiency. The impact of scale deposition on the metrological performance of the meter is illustrated and the procedures for quantification and compensation for maintaining the measurement quality over time is presented. Introduction Deposition of scale represents a major threat to flow assurance, with particularly serious consequences on subsea developments, and it poses serious challenges to maintaining production and processes optimisation. It can represent a large loss of production and diminish a field's net present value. Tjomsland et al1 quantified the value of scale control in the Veslefrikk field in Norway at U.S. dollars 1.1 billion. Quantification of scale deposition is of primary importance for the determination of remedial / corrective action. In some areas such as Canada and the North Sea, where entire regions are prone to scale, scale is recognized as one of the top production challenges. Many mechanisms can lead to the deposition of scale in the reservoir, in the completion, in surface lines and production process equipment. For example, scale can be generated by the incompatibility between injected seawater and reservoir water. Van Khoi Vu et al2 report that more than 320 g of barium sulphate could potentially be deposited per cubic meter of coproduced water in the Girassol field in Angola. Scale can develop in the formation pores near the wellbore - reducing formation porosity and permeability. It can block flow by clogging perforations or forming a thick lining in production tubing. It can also coat and damage production completion equipment such as safety valves, gas lift mandrels and nipples. Scale also accumulates in surface production equipment, such as well heads, master and wing valves, manifolds, flow lines, water knockouts, and test and production separators. It may clog up control lines and wet legs of instruments, affect the proper operation of automatic control and emergency shut down valves all of which are detrimental to production and increase field maintenance costs. Scale deposition may be somewhat controlled in a number of ways such as: injection of inhibitors, chemical or mechanical removal, by changing the operating conditions - pressure, temperature and the composition of injected water. Some mineral scales can be dissolved and removed by acids, whilst most others cannot. Mitigating scale therefore is a difficult task often involving a combination of the above techniques.
A new technique is presented to detect scale deposition and to determine its composition and thickness in real-time in oilfield tubing and pipe. The method is based on continuous triple-energy gamma-ray attenuation measurements made at a dedicated, instrumented mandrel or spool piece. Detection and identification of extremely thin scale deposits are possible without disrupting the flow. Simulations of scale deposits in a three-phase pipe are given to demonstrate the method's practical application. The feasibility of the method has been verified with field measurements. The instrumentation required is based on existing technology with a proven track record in field conditions. Surface installations are safe to operating personnel and the environment. This new method enables a simple monitoring device to detect and characterize scale in its earliest stages of formation. The technique may be used to determine the appropriate type of inhibition or removal treatment according to the type of scale present, to evaluate the effectiveness of scale treatments in-situ in the pipe in real-time, and can help to optimize chemical consumption for continuous treatment. Introduction The problem of scaling in production tubulars (tubing and piping) is widespread. Scale deposits appear in several forms and are caused by several different phenomena. Scale may appear as the result of waterflooding, production commingling or simply the depressurization of the fluids as they flow to surface. What is common to all scale occurrences is that the mineral content of the fluid (usually water) has exceeded the fluid's saturation point in response to a change in conditions. The change in conditions may be a mixing of different waters, changes in temperature and pressure, water evaporation, or water chemistry and pH changes (such as due to CO2 out-gasing). As the mineral's saturation point is exceeded, unstable crystal nuclei evolve and devolve until they grow a critical radius, at which point the surface free energy of the nuclei decreases and crystal growth is spontaneous1. Crystal nucleation usually occurs against a substrate, such as scale growth on a pipe wall, because the crystal nuclei are more stable growing against a surface. Nucleation occurs more readily when the interfacial tension between the crystal and the substrate is very small. Crystal growth on a crystal substrate is highly favorable, which explains why scale can build up rapidly. The nature of scale formation in oilfield tubulars is unique by its environment. Oilfield scale forms in the presence of oil and gas, waxes and surfactants, metal corrosion, and in turbulent and high velocity flow. Oilfield scale often is composed of more than one mineral. It is not uncommon for several different compounds to be deposited together or in layers. Wax, oil and iron oxide can be trapped within the scale formation. Even the density of the scale can vary, depending on the depositional conditions. Treating oilfield scale is a complex challenge. In certain regions prone to scaling, such as the North Sea and Canada, treatments to prevent or minimize scale formation are well engineered and commonly practiced. Nevertheless, these treatments are not always completely effective. For instance, a inhibition treatment applied uniformly to several wells with different scaling tendencies may result in some wells being under-treated, allowing scale to form. When scale is multi-component, a treatment may be only partially effective. Over time, inhibition treatments lose effectiveness as the production environment changes, re-creating scaling conditions. Despite the best efforts to control it, scale deposits in production tubulars and surface facilities disrupt production and cause costly intervention work. The literature is replete with examples of the consequences of scale. In fact, there seems yet to be published a useful aspect of scale deposition in oil and gas production systems.
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