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This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 166652, "Use of Sonar Metering To Optimize Production in Liquid-Loading-Prone Gas Wells," by C.A. Shields and M. Dollard, Marathon Oil UK, and S. Sridhar, G. Dragnea, and M. Illingsworth, Expro Meters, prepared for the 2013 SPE Offshore Europe Oil and Gas Conference and Exhibition, Aberdeen, 3-6 September. The paper has not been peer reviewed.
This paper discusses the use of clamp-on sonar flowmeters to minimize losses associated with well testing and to gain the subsequent benefits seen with respect to production optimization and well deliquefication. Clamp-on sonar flowmetering is a nonintrusive technology that measures the flow velocity of the fluid stream. This intensive well-management strategy has assisted in reducing the production decline of the East Brae field in the North Sea.
The East Brae platform (Fig. 1) is located 275 km northeast of Aberdeen in Block 16/3a in a water depth of 110 m. The reservoir comprises high- permeability sands deposited by turbidity currents. The reservoir has an average porosity of 17% and an average permeability of 558. md. The platform initially started producing condensate, while reinjecting the gas, in December 1993. Exporting of the gas began in 1994, and reinjection was phased out. The current topside holds a low- pressure (LP) separator (test separator) operated at 217 psig, a high-pressure (HP) separator (first-stage separator) currently operated at 406 psig, and second- and third-stage separators. It also includes a gas-processing and - dehydration plant, three gas-compression trains, and produced-water-processing facilities for discharge into the sea.
There are currently 12 producing monobore wells on the East Brae platform. Former gas-injection wells have now been converted to producing wells. The wells are inclined up to a maximum deviation of 45°. The reservoir fluid is a retrograde gas condensate that exhibits compositional variation with depth. The reservoir has an active aquifer that has encroached into the producing layers as reservoir pressure has depleted through production.
Background: Allocation and Well Testing
On the East Brae platform, production allocation for the wells has typically been carried out by individual well tests of each well in the test separator on a monthly basis. The well test records the amount of oil and gas produced from a well during the first stage of separation. The oil and gas are then processed further in the plant. Some of the oil is vaporized into the gas phase as it is stabilized in lower-pressure separators, and some of the gas is liquefied as it is cooled and compressed. As a result of these equilibrium changes, the oil and gas rates exported from the platform (known as its “potentials”) that are attributable to a single well are not directly comparable with the oil and gas rates measured at the test separator for that well.
Abstract The East Brae platform is located in UK Block 16/3a and is operated by Marathon Oil U.K. LLC. The platform has a high pressure (HP) separator 406 psig (28 barg) and a test separator operating as a low pressure (LP) production separator 217 psig (15 barg). There are currently 12 producing gas wells; varying water-gas ratios and low gas rates result in liquid loading being a major flow assurance issue. This paper discusses the use of clamp-on sonar flow meters to minimize losses associated with well testing and the subsequent benefits that were seen with respect to production optimization and well deliquification. Clamp-on sonar flow metering is a non-intrusive technology which measures the flow velocity of the fluid stream. Sonar meters have been deployed every two months to facilitate routine production well testing of all wells to meet allocation and field management requirements. Prior to sonar metering, wells capable of only flowing to the LP separator needed to be shut-in to allow individual well tests. Wells can now be individually sonar well tested without production interruption. Different methods have been adopted to optimize production and combat liquid loading. ‘Swing’ wells use the LP separator to unload liquids and thus improve their subsequent performance in the HP separator. Sonar metering determined the optimal cycle frequency for individual wells, allowing Marathon Oil to keep the LP separator full and maintain maximum rates in the HP separator. Wireless wellhead temperature sensors have been recently installed and have been correlated to sonar measured gas rates in the well bore, providing a real-time trend of liquid loading and well performance. Currently 75% of the well stock is cycled every 4 hours in order to optimize production. This intensive well management has assisted in reducing the production decline of the East Brae field.
Abstract Centrica Energy operates the South and North Morecambe Fields, which are among the largest in the UK Continental Shelf in terms of original reserves. Current production is approximately 200 million cubic feet of gas per day, which is 5% of the indigenous UK production or 3.5% of the UK gas demand. Monitoring real-time production surveillance rates from each well in the field provides critical information for Centrica Energy's reservoir management and workover planning. Centrica Energy explored the range of potential replacement technologies for the existing venturi meters, including installing new in-line differential pressure meters of several types, as well as traditional ultrasonic type meters. Parameters considered include the cost of acquisition, installation and the total cost of ownership, measurement quality and repeatability. Turndown ratio, or the instrument's measurement range, was also an important consideration as this instrument was expected to measure well production throughout the declining life of the field. In 2010, Centrica Energy trialed a SONAR meter on one well to assess its applicability to the well conditions in the Morecambe fields. The SONAR meters, applied at that time, were a new class of SONAR meter technology that had been developed specifically for Type I and Type II wet gas wellhead measurement. After evaluating the performance of the SONAR meter for one year, Centrica Energy installed SONAR flow meters on all 44 producing wells across 6 platforms. SONAR meters clamp onto the existing pipework allowing installation without shutting in the well and incurring the associated lost production, reducing management of change and HSE exposure. This paper describes the importance of real-time production surveillance for reservoir management and for making informed decisions concerning workover strategy and prioritization. In addition, this paper presents the production data collected over an extended time period and the challenges presented by the field wide implementation of a new class of flow meter technology.
Hussein, Ahmed (Exprogroup) | Alqassab, Mohammed (Exprogroup) | Atef, Hazem (Exprogroup) | Sirdhar, Siddesh (Exprogroup) | Alajmi, Salem Abdullah (KOC) | Aldeyain, Khaled Waleed (KOC) | Hassan, Mohamed Farouk (KOC) | Goel, Harrish Kumar (KOC)
Abstract Umm Gudair (UG) field is one of the major oil fields of West Kuwait asset. Wells are tested periodically using multiple conventional test separators and data is subsequently used to update Well Performance "Nodal analysis" and "Live Flow Line Surface Network Model". A different approach was tested in 2018 for a mature oil field in the Middle East to evaluate the effectiveness of Clamp-On based SONAR Flow Surveillance solution against existing conventional portable test separator. The objective was to check the performance of the SONAR Flow Surveillance on black oil wells at different flowing conditions, and ultimately implement a new approach to increase the testing frequency, reduce any potential of hydrocarbon release, avoid well shutdown, optimize operating costs, and production optimization. The SONAR Surveillance approach is based on SONAR clamp-on flow meters deployed in conjunction with compositional (PVT) and multiphase flow models for oil and gas wells to interpret the measurements of the SONAR flow meters at line conditions (pressure, temperature, fluid stream composition), and output the gas, oil and water phase flow rates at both actual and standard conditions. The SONAR meter measures the bulk flow velocity (at line conditions), then a flow computer determines the individual phase volume fractions at actual conditions using a PVT model and water-cut. This provides a measure of the oil rate at actual conditions. A shrinkage factor calculated by the black oil model is applied to report oil rate at standard conditions. Gas and water are also inferred in a similar manner. The gas, oil and water flow rates thus determined at actual conditions are further processed and converted to standard conditions as well. The field tests showed that the SONAR Flow Surveillance approach allowed more flexibility in terms of field installation and the measurements are made at actual production conditions unlike other devices that may introduce additional flow restrictions. The SONAR meters diagnostics also provided a more realistic representation of the well flow profile since the measurements are instantaneous versus the "averaging" effects observed when using gravity-based separators. This allows better production surveillance and understanding of changes in well behavior.
Brady, Jerry (BP Exploration, Alaska, Inc) | Igbokwe, Chidiebere (BP Exploration, Alaska, Inc) | Montague, Stuart (BP Exploration, Alaska, Inc) | Warren, Mike (BP Exploration, Alaska, Inc) | Stadnicky, Nick (BP Exploration, Alaska, Inc) | Linder, Mathew (BP Exploration, Alaska, Inc) | Hall, Andrew (BP Exploration Operating Company, Ltd.) | Mehdizadeh, Parviz (Production Technology, Inc.) | Roberts, Bart (Weatherford International, LLC) | Lievois, John (Weatherford International, LLC) | Rodriguez, Daniel J. (Weatherford International, LLC)
Copyright 2013, Society of Petroleum Engineers This paper was prepared for presentation at the SPE Annual Technical Conference and Exhibition held in New Orleans, Louisiana, USA, 30 September-2 October 2013. This paper was selected for presentation by an SPE program committee following review of information contained in an abstract submitted by the author(s). Contents of the paper have not been reviewed by the Society of Petroleum Engineers and are subject to correction by the author(s). The material does not necessarily reflect any position of the Society of Petroleum Engineers, its officers, or members. Electronic reproduction, distribution, or storage of any part of this paper without the written consent of the Society of Petroleum Engineers is prohibited. Permission to reproduce in print is restricted to an abstract of not more than 300 words; illustrations may not be copied. The abstract must contain conspicuous acknowledgment of SPE copyright. Abstract Alaska's North Slope oil fields offer several different types of production environments that can prove challenging for effective production well testing with conventional gravity type test separators. The Prudhoe Bay field has mature production: high water cuts exceeding 90%, crudes with low 20s API gravity and gas-lifted wells with high gas volume fractions (GVF) 99.9%. The Milne Point field has viscous crude and light oil production and employs electrical submersible pumps (ESP), jet pumps and gas lift. This wide range of production methods and challenging fluid properties create challenges when analysing potential equipment and procedures to provide the critical production data needed to optimize overall production. Over the last several years, BP Exploration (Alaska) Inc. (BPXA), installed over 24 infrared water-cut sensors.