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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 The paper has not been peer reviewed.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.
The concept of compact separation is attractive in a number of operating environments. These include offshore and arctic operations where both space and weight are at a premium and subsea and downhole processing where space is very limited. Compact separators often rely on centrifugal forces to enhance the separation process and are therefore highly dependent on inlet geometry. This paper investigates expanding the operational envelope of a compact Gas Liquid Cylindrical Cyclone separator through the use of a novel inlet, which can be easily altered to respond to changing well conditions. To demonstrate the importance of inlet geometry, historical production from the Gloyd-Mitchell zone of the Rodessa Field in Louisiana was examined over a 40-month period. As in most oil field production, there were significant changes in the water cut and GOR. This field data clearly shows that a compact separator equipped with single inlet geometry is not able to perform effectively over the wide range of conditions exhibited in a typical oil field. This paper models the hydrodynamics in the separator inlet. Three different inlet geometries were investigated through the use of a changeable inlet sleeve. New experimental data were acquired utilizing a 7.62-cm I.D compact separator, which was 3.0 m in height. The effect of inlet geometry on separator performance was investigated over a wide range of flow conditions. Fluid viscosities from 1-12 cp and the effect of fluid level within the separator were also examined. The results indicate that the operational envelope for liquid carry-over and gas carry-under can be expanded by more that 300% by altering the inlet to respond to changing field conditions.
Economic pressures continue to force the petroleum industry to seek less expensive and more efficient alternatives to conventional separators. Recently, the compact separator has been proposed as a key element in reducing cost of production operations. Compact separators, such as the Gas-Liquid Cylindrical Cyclone are becoming increasingly popular as attractive alternatives to conventional separators, as they are simple, compact, low weight, low-cost, require little maintenance, and are easy to install and operate. In addition, gas-liquid cylindrical cyclones are used to enhance the performance of multiphase meters, multiphase flow pumps, and de-sanders, through control of the gas- liquid ratio. Compact separators are also used as partial separators, portable well testing equipment, flare gas scrubbers, slug catchers, down-hole separators, pre-separators and primary separators.
Presently, more than a hundred and fifty gas-liquid cylindrical cyclone units have been installed and put into use in the field for various applications (Wang et al., 2000).1 The size of these compact separators varies from 7.62-cm. to 1.52-m in diameter and 2.13-m to 9.14-m in height. The gas liquid cylindrical cyclone separator is a simple device, which has neither moving parts nor internal devices. It is a vertically installed pipe/vessel mounted with a downward inclined tangential inlet, with outlets for gas and liquid provided at the top and bottom, respectively. The two-phases of the incoming mixture are separated due to the centrifugal/buoyancy forces caused by swirling motion and gravity forces. The heavier liquid is forced radially towards the wall of the cylinder and is collected from the bottom, while the lighter gas moves to the center of the cyclone and is taken out from the top.
Applications of gas-liquid cylindrical cyclone can be in a metering loop configuration, where the gas and liquid outlets are recombined, or in a separation configuration, where the gas and liquid outlets are separated. The metering loop configuration is capable of self-regulating the liquid level for small flow variations. However, compact separator used in separation configuration must have liquid level and/or pressure control so as to prevent, or delay, the onset of liquid carry-over (LCO) into the gas stream or gas carry-under (GCU) into the liquid stream.
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.
Vieira, R. E. (The University of Tulsa) | Sajeev, S. (The University of Tulsa) | Shirazi, S. A. (The University of Tulsa) | McLaury, B. S. (The University of Tulsa) | Kouba, G. (Chevron Energy Technology Company)
Erosion experiments were conducted with gas-sand and gas-liquid-sand flow conditions varying air and water velocities in a laboratory scale Gas-Liquid Cylindrical Cyclone Separator (GLCC). The location of highest erosion measured for gas-liquid-sand conditions was slightly above the case for the gas-sand condition, but the magnitude of erosion for the latter case was much higher than the former. Therefore, it appears that the presence of a small amount of liquid in this geometry reduces the peak value of measured erosion. Computational Fluid Dynamics (CFD) simulations are also conducted for gas-sand flows to aid in the understanding of the particle flow characteristics and maximum wall thickness loss inside the GLCC. The results from the simulation are compared to experimental data for several conditions. A simplified erosion prediction model has been also developed to predict the erosion occurring at the inlet nozzle region of the GLCC. The model predictions agree much better with data than those previously obtained for the GLCC geometry that was based on an elbow but similar methodology was applied.
The oil industry relies mainly on conventional gravity based vessel-type separators to process gas–liquid mixtures produced from oil/gas wells (1). After several decades of use, their technology has reached an advanced degree of maturity and their design is well established. However, they are bulky, heavy and expensive to manufacture and operate. The increasing number of offshore exploitations and the need to cut down platform and equipment costs have motivated the oil and gas industry to search for new and compact gas–liquid separators.The GLCC (Gas-Liquid Cylindrical Cyclone Separator) (2, 3) has been widely accepted as an alternative to conventional vessel-type separators during recent years. The GLCC is a simple separator, which has neither moving parts nor internal devices. It consists of a vertical pipe with a downward inclined tangential inlet (that generally ends with a nozzle) located approximately at mid-height of the separator body, and two outlets respectively at the top and bottom of the pipe (Fig. 1a). The tangential inlet provides swirling motion to the incoming mixture. The phase separation process is enhanced by the resulting centrifugal force. During regular operation, the gas exits from the top while the liquid is collected from the bottom outlet.
Summary Field results of Auger separator installations are presented which demonstrate the following new applications of in-line gas/liquid partial separation:increasing separation vessel capacity (or reducing required vessel size for a given flow rate) and reducing pressure drop in multiphase lines that transport produced hydrocarbons. The Auger separator is a device which partially separates liquid and gas, has no moving parts, and requires no power or level controls. The diameter of the separator is typically a few inches, generally about the same diameter as the line, and is installed as a spool piece in the line. In one application, a field test was conducted where the Auger separator was placed just upstream of a conventional test separator. By removing a portion of the gas upstream, the liquid capacity of the vessel was approximately doubled. In a different application, Auger separators were installed to remove gas from multiphase-flowlines and provide raw gas lift on the drillsite. By doing this, the amount of gas in the production line was reduced, decreasing the backpressure and increasing the capacity for produced fluids. The operating conditions before and after the installations, equipment descriptions and photographs, piping layouts, and operational considerations are included. The design of the Auger separators and performance comparisons to predictions from design equations are also discussed. Introduction The Greater Point McIntyre area is located on the North Slope of Alaska, in the vicinity of Prudhoe Bay. Five separate fields, on eight drillsites, share a central processing facility. Wells on each drillsite flow to a manifold where production can be diverted to either a test separator or to the production header. The Auger separator is a device which partially separates liquid and gas. The development and initial testing of this separator are described in Ref. 1. It has no moving parts, and requires no power or level controls. The diameter of the separator is typically a few inches, generally about the same diameter as the line, and is installed as a spool piece in the line. It can be installed horizontally, vertically, or any angle in between. Because of these features, installation cost is low and maintenance is minimal. In this separator, the gas and liquid are separated when the multiphase fluid enters an Auger section where the pitch of a stationary Auger blade causes the flow to rotate. This rotation forces the liquid to flow along the outer wall with the gas flowing in the center. A portion of the gas then flows into ports in the Auger core, and so becomes separated. The amount of separated gas is controlled by backpressure, using chokes on the gas and liquid outlet lines. There are many applications where partial separation of gas is beneficial. The two discussed in this paper are increasing the capacity of a conventional gas/liquid separation vessel and debottlenecking multiphase lines and gas-limited facilities. Although the Auger separator was used in these applications, other compact separation devices could be used as well. Reviews of many of those devices are contained in Refs. 2 through 4. We selected the Auger separator because it required no additional instrumentation or controls and only minor piping changes. As a result, the installed cost was approximately U.S. $20,000 compared to about U.S. $1 million for a conventional separator and about U.S. $500,000 for a cyclonic-type vertical compact separator with level control. Vessel Capacity Tests At each drillsite, individual well production rates are measured with a conventional test separator vessel. Point McIntyre drillsite PM2 has two test separators. Lower-rate wells can be tested with one separator, but higher-rate wells must be tested by flowing into both separators in parallel. They are two-phase (liquid/gas) separators. The gas rate is measured with an orifice meter. The liquid rate is measured with a coriolis meter, and water cut is measured with a microwave water-cut meter. Each vessel is about 5 ft diam by 15 ft long. The highest rates historically possible to test through one separator were approximately 8,000 BLPD and 6.5 MMSCFD. At rates higher than this, separation was incomplete, causing either gas to be carried under into the liquid leg or liquid to be carried over with the gas stream. The purpose of the tests was to investigate whether the capacity of the conventional test separator shown in Fig. 1 could be increased by separating a portion of gas upstream with the Auger separator, metering it separately, and sending a lower gas/oil ratio (GOR) stream to the separator. Removing some of the gas would help by reducing the total fluids passing through the separator. It was also thought that foaming would be reduced by lowering the gas rate, reducing required residence time. To evaluate how much the separator capacity could be increased, design calculations were performed, using a standard conventional horizontal separator analysis program. Those results predicted that the nominal separator capacity (at normal liquid level) was 6,300 BLPD and 38 MMSCFD. At high liquid level and minimal residence time, the capacity was calculated to be 12,800 BLPD and 35 MMSCFD. In neither case was the gas rate from a well predicted to be a limit on capacity. In practice, the separator was able to handle the nominal liquid rate, but was never able to come close to handling the gas rate predicted, and had never been able to achieve the liquid rate corresponding to operation at the high liquid level. Because the model predictions did not agree with operating experience, we decided to proceed with the tests.