Subsurface Compressor System Improves Gas Production in Unconventional Reservoirs

2021 ◽  
Vol 73 (07) ◽  
pp. 62-63
Author(s):  
Chris Carpenter
Keyword(s):  
High Speed ◽  
Magnetic Coupling ◽  
Gas Production ◽  
Flow Path ◽  
Gas Well ◽  
Recoverable Reserves ◽  
Artificial Lift ◽  
Wet Gas ◽  
Gas Compression ◽  
Straight Flow

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 201138, “Liquid Removal To Improve Gas Production and Recoverable Reserves in Unconventional Liquid-Rich Reservoirs by Subsurface Wet Gas Compression,” by Lukas Nader, SPE, David Biddick, SPE, and Herman Artinian, SPE, Upwing Energy, et al., prepared for the 2020 SPE Virtual Artificial Lift Conference and Exhibition—Americas, 10–12 November. The paper has not been peer reviewed. This paper describes an artificial lift technology, a subsurface compressor system (SCS), that simultaneously removes liquids, increases gas production, and improves recoverable reserves in gas wells. The subsurface compressor can reverse the vicious cycle of liquid loading, which decreases gas production from a gas well and leads to premature abandonment, by creating a virtuous cycle of increased gas and condensate production. The first field trial of the technology in an unconventional shale gas well supports the mechanism of subsurface gas compression and its benefit to unconventional gas production. The SCS This paper focuses on the latest deployed design. As with all SCS systems, this unit has three major components (Fig. 1). High-Speed Motor. The motor is a four-pole, high-speed, permanent-magnet (PM) synchronous topology. The motor maximum operating speed is 50,000 rev/min, with a 55,000-rev/min overspeed. Surface-mounted PMs are retained on the shaft surface. A sine filter is also used to minimize harmonic losses in the rotor, eliminating the need for active cooling flow in the rotor cavity. With the motor housing hermetically sealed from the environment and maintaining a low pressure within the housing, a minimum life of 20 years is expected from the electrical motor section. The motor rotor is levitated with passive magnetic bearings, requiring no lubrication or a pressurized air source, to support the high-speed rotating shafts. Magnetic Coupling. The magnetic coupling consists of three major components: the male and female ends of the magnetic coupling as well as the isolation can in between. The female end of the magnetic coupling is attached directly to the motor. The isolation can is used to seal the female magnetic coupling section hermetically within the body of the PM motor from the environment. Using a magnetic coupling to transmit torque through an isolation can is one of the key features of the protectorless, rotating, sealless motor system to ensure reliability of the motor. Hybrid Wet Gas Compressor. The compressor is a multistage hybrid axial flow wet compressor. The key advantage of this proprietary compressor design is its relatively straight flow path compared with those of centrifugal compressors. When the flow path is straight, with little change of direction, the heavier constituents, including liquids and solids, will follow the gas phase because there is little or no centrifugal force to separate the high-density phases from the low-density one. Also, erosion of the compressor parts is minimized by the straight flow pattern because of the lower probability of impingements of solid particles on the compressor internal surfaces compared with the torturous internal paths of centrifugal compressors. The remainder of the system, as well as the deployment, is very similar to an electrical submersible pump.

Liquid Removal to Improve Gas Production and Recoverable Reserves in Unconventional Liquid-Rich Reservoirs by Subsurface Wet Gas Compression

2020 ◽  
Author(s):  
Lukas Nader ◽  
David Biddick ◽  
Herman Artinian ◽  
Pandurang Kulkarni ◽  
Bob Van Hoy ◽  
...  
Keyword(s):  
Gas Production ◽  
Recoverable Reserves ◽  
Wet Gas ◽  
Gas Compression ◽  
Liquid Removal

Failures of the High Energy, High Pitch Velocity Gear Boxes

2004 ◽  
Author(s):  
Steve Ingistov
Keyword(s):  
High Speed ◽  
Oil And Gas ◽  
High Energy ◽  
Gas Production ◽  
High Pitch ◽  
Oil And Gas Production ◽  
Mean Time Between Failures ◽  
Gear Teeth ◽  
Root Cause ◽  
Gas Compression

This Paper describes the on-going efforts of finding the root-cause for the failures of high-energy (over 30,000 HP), high-pitch velocity (over 30,000 FPM) gear elements. These gear elements are presently operating in Oil and Gas Production Facilities. They are installed between the GT drivers and turbo-compressors. Turbo-compressors deliver high-pressure gas into the underground oil fields to enhance the oil production. The oldest Gas Compression Units were commissioned in 1995 and the latest in 1998. Since installation in 1995 at least 6 gear boxes experienced failures of the pinion (high speed gear) teeth. The Mean Time Between Failures (MTBF) of the pinion teeth was estimated around 34,000 operating hours. The costly shutdown of Gas Compression Units forced the management to seek advice within the company. The intent of this Paper is to share some field experiences and to present some corrective actions. The intent of this Paper is also to help Original Equipment Manufacturers (OEMs) in this case gear elements Manufacturers to develop better balance between cost, life and reliability. Sometimes the balance between these three parameters is difficult to maintain. Too often the gear elements Manufacturers are forced to compete on the price basis and as result the quality of the gear elements are sometimes compromised. In addition, several well-known gear elements Manufacturers stopped offering high energy, high-pitch velocity gear elements because they suffered serious failures of the gear elements on the test stand and also in the field.

Multiphase gas compression to boost unconventional production and reserves

2019 ◽  
Vol 59 (1) ◽  
pp. 268
Author(s):  
Robert Perry ◽  
Jeffrey Martini ◽  
Pandurang Kulkarni
Keyword(s):  
Atmospheric Pressure ◽  
Gas Production ◽  
Unconventional Reservoirs ◽  
Operational Flexibility ◽  
Flow Conditions ◽  
Artificial Lift ◽  
Gas Compression ◽  
Order Of Magnitude ◽  
Inflow Performance ◽  
Gas Lift

Hydraulic fracturing has significantly increased well inflow performance in unconventional reservoirs, enabling their economic development. This improved inflow performance has opened up the possibility of leveraging further reserves and production gains through artificial lift or similar production enhancement techniques. A ‘multiphase compressor’ has been developed with differentiating characteristics:compression ratios of up to 40:1 (an order of magnitude greater than conventional compressors), ability to handle a broad range of multiphase conditions, and significant operational flexibility. This makes it very well suited for deployment in unconventional reservoirs at the wellhead, either on its own in a multiphase boosting capacity or in conjunction with other forms of artificial lift (such as gas lift, plunger lift, and potentially downhole pumping). The multiphase compressor has been deployed in the field on naturally flowing wells, and wells with plunger lift. Production rate increases of up to 300% were achieved, and production was maintained in wells that would have otherwise loaded up and died. Wells were unloaded by reducing wellhead flowing pressures to atmospheric pressure at the compressor suction – similar to flowing the well into an ‘open topped’ tank. The multiphase compressor demonstrated a very broad operating range and the ability to handle slug flow conditions. Further applications to be tested include gas lift and downhole pumping in shale wells, gas wells that have received fracture hits and require clean up from invaded fracture fluids, and coal seam gas production. Multiphase compression has significant potential to increase both production and reserves from unconventional reservoirs and wells.

Wet Gas Compression: Characterizing Two-Phase Flow Inside a Compressor With Flow Visualization

2017 ◽  
Author(s):  
Melissa Poerner ◽  
Ryan Cater ◽  
Craig Nolen ◽  
Grant Musgrove ◽  
David Ransom
Keyword(s):  
Flow Visualization ◽  
Flow Structure ◽  
Two Phase Flow ◽  
Gas Production ◽  
Liquid Volume ◽  
Phase Flow ◽  
Two Phase ◽  
Wet Gas ◽  
Gas Compression ◽  
Compressor Performance

Wet Gas Compression (WGC) continues to be an important topic as oil and gas production is driven further out into the ocean and moves critical equipment to the ocean floor. In the last year, significant milestones have been reached for WGC by the installation of the first wet gas compressor off the coast of Norway. Even with this achievement, there is a lack of understanding of the physics behind WGC and there are deficiencies in the ability to predict the compressor performance. Understanding the two phase flow structure inside the compressor is important for validating WGC simulations and being able to predict compressor performance. This paper reviews the results from a test program focused on characterizing the flow inside the compressor by using flow visualization. An open impeller centrifugal compressor was outfitted with windows to view the flow inside the compressor at the inlet, inside the impeller and in the diffuser section. Testing was conducted with an ambient suction pressure at various compressor speeds, flow rates, and liquid volume fractions. Images and videos were captured at the different conditions in order to observe the two phase flow structure. The general patterns and trends that characterize wet gas flow are discussed in this paper.

An Approach to Compact, Wet Gas Compression

2010 ◽  
Author(s):  
Jose´ L. Gilarranz R. ◽  
H. Allan Kidd ◽  
Gocha Chochua ◽  
William C. Maier
Keyword(s):  
High Speed ◽  
Oil And Gas ◽  
Integrated Approach ◽  
Separation Unit ◽  
Compression System ◽  
Wet Process ◽  
Process Gas ◽  
Wet Gas ◽  
Sea Bed ◽  
Gas Compression

In recent years, several papers have been written regarding the use of centrifugal compression technology to handle applications in which the process gas entering the equipment contains a significant amount of liquids, and can therefore be considered a wet gas. One such application that is currently being considered by many oil and gas operators is the installation of processing and compression equipment on the sea bed, to directly handle the process gas stream in close proximity to the wellhead. Other applications also exist topside, in which the operator would benefit from the installation of additional compression and processing capabilities at brown field facilities. Most of these existing installations have limited space for expansion and have strict size and weight limitations that have to be met by the additional equipment. This, in many cases, hinders the utilization of traditional compression and processing equipment, which is typically arranged using the large and heavy multi deck approach. A novel integrated compression system (ICS) has recently been developed to address the current need for compact compression systems that can handle wet process gas. The ICS makes use of centrifugal compressor stages driven directly by a high-speed, close-coupled electric motor, and incorporates a proprietary integrated centrifugal gas-liquid separation unit within the compressor case. This compact compression unit is packaged with process gas coolers in a single-lift module, providing a complete compression system that can be applied to all markets — upstream, midstream and downstream. With this integrated approach, the total footprint and weight of a conventional module or equipment layout can be greatly reduced. This paper is part of a series of publications that will describe the attributes of the new integrated compression system, and will serve to introduce the ICS and the benefits associated to the integration of the centrifugal separator into the compressor casing. The paper will focus on the OEM’s approach to Wet Gas Compression, with emphasis on the benefits of handling the liquid and vapor phases as separate streams, making the system more efficient and reliable than alternate solutions, including the ones that handle the wet gas directly. Finally the paper will provide a comparison between a traditional compression train and the new ICS to show how the latter system offers significant size and weight advantages.

A Magnetic Drive Actuator for Micro Electrical Discharge Machining

2012 ◽  
Vol 591-593 ◽  
pp. 303-306
Author(s):  
Xiao You Zhang ◽  
Akio Kifuji ◽  
Dong Jue He
Keyword(s):  
Electrical Discharge ◽  
High Speed ◽  
Degrees Of Freedom ◽  
Electrical Discharge Machining ◽  
Magnetic Coupling ◽  
Magnetic Bearings ◽  
Coupling Mechanism ◽  
Micro Electrical Discharge Machining ◽  
Long Stroke ◽  
Magnetic Drive

Electrical discharge machining has the capability of machining all conductive materials regardless of hardness, and has the ability to deal with complex shapes. However, the speed and accuracy of conventional EDM are limited by probability and efficiency of the electrical discharges. This paper describes a three degrees of freedom (3-DOF) controlled, wide-bandwidth, high-precision, long-stroke magnetic drive actuator. The actuator can be attached to conventional electrical discharge machines to realize a high-speed and high-accuracy EDM. The actuator primarily consists of thrust and radial magnetic bearings, thrust and radial air bearings and a magnetic coupling mechanism. By using the thrust and radial magnetic bearings, the translational motions of the spindle can be controlled. The magnetic drive actuator possesses a positioning resolution of the order of micrometer, a bandwidth greater than 100Hz and a positioning stroke of 2mm.

Wettability Alteration to Intermediate Gas-Wetting in Gas-Condensate Reservoirs at High Temperatures

SPE Journal ◽  
2007 ◽  
Vol 12 (04) ◽  
pp. 397-407 ◽  
Author(s):  
Mashhad Mousa Fahes ◽  
Abbas Firoozabadi
Keyword(s):  
Hydraulic Fracturing ◽  
Production Rate ◽  
High Temperatures ◽  
Gas Production ◽  
Reservoir Rock ◽  
Wettability Alteration ◽  
Absolute Permeability ◽  
Low Permeability ◽  
Gas Well ◽  
Water Blocking

Summary Wettability of two types of sandstone cores, Berea (permeability on the order of 600 md), and a reservoir rock (permeability on the order of 10 md), is altered from liquid-wetting to intermediate gas-wetting at a high temperature of 140C. Previous work on wettability alteration to intermediate gas-wetting has been limited to 90C. In this work, chemicals previously used at 90C for wettability alteration are found to be ineffective at 140C. New chemicals are used which alter wettability at high temperatures. The results show that:wettability could be permanently altered from liquid-wetting to intermediate gas-wetting at high reservoir temperatures,wettability alteration has a substantial effect on increasing liquid mobility at reservoir conditions,wettability alteration results in improved gas productivity, andwettability alteration does not have a measurable effect on the absolute permeability of the rock for some chemicals. We also find the reservoir rock, unlike Berea, is not strongly water-wet in the gas/water/rock system. Introduction A sharp reduction in gas well deliverability is often observed in many low-permeability gas-condensate reservoirs even at very high reservoir pressure. The decrease in well deliverability is attributed to condensate accumulation (Hinchman and Barree 1985; Afidick et al. 1994) and water blocking (Engineer 1985; Cimolai et al. 1983). As the pressure drops below the dewpoint, liquid accumulates around the wellbore in high saturations, reducing gas relative permeability (Barnum et al. 1995; El-Banbi et al. 2000); the result is a decrease in the gas production rate. Several techniques have been used to increase gas well deliverability after the initial decline. Hydraulic fracturing is used to increase absolute permeability (Haimson and Fairhurst 1969). Solvent injection is implemented in order to remove the accumulated liquid (Al-Anazi et al. 2005). Gas deliverability often increases after the reduction of the condensate saturation around the wellbore. In a successful methanol treatment in Hatter's Pond field in Alabama (Al-Anazi et al. 2005), after the initial decline in well deliverability by a factor of three to five owing to condensate blocking, gas deliverability increased by a factor of two after the removal of water and condensate liquids from the near-wellbore region. The increased rates were, however, sustained for a period of 4 months only. The approach is not a permanent solution to the problem, because the condensate bank will form again. On the other hand, when hydraulic fracturing is used by injecting aqueous fluids, the cleanup of water accumulation from the formation after fracturing is essential to obtain an increased productivity. Water is removed in two phases: immiscible displacement by gas, followed by vaporization by the expanding gas flow (Mahadevan and Sharma 2003). Because of the low permeability and the wettability characteristics, it may take a long time to perform the cleanup; in some cases, as little as 10 to 15% of the water load could be recovered (Mahadevan and Sharma 2003; Penny et al. 1983). Even when the problem of water blocking is not significant, the accumulation of condensate around the fracture face when the pressure falls below dewpoint pressure could result in a reduction in the gas production rate (Economides et al. 1989; Sognesand 1991; Baig et al. 2005).

Pushing 30 Years Multiple Brown Fields Limits Through Artificial Lift and Facilities Improvement

2021 ◽  
Author(s):  
Mohd Hafizi Ariffin ◽  
Muhammad Idraki M Khalil ◽  
Abdullah M Razali ◽  
M Iman Mostaffa
Keyword(s):  
New Technology ◽  
Lessons Learned ◽  
Oil Fields ◽  
Submersible Pump ◽  
Large Space ◽  
Gas Well ◽  
Wellhead Pressure ◽  
Artificial Lift ◽  
Electrical Submersible Pump ◽  
Gas Lift

Abstract Most of the oil fields in Sarawak has already producing more than 30 years. When the fields are this old, the team is most certainly facing a lot of problems with aging equipment and facilities. Furthermore, the initial stage of platform installation was not designed to accommodate a large space for an artificial lift system. Most of these fields were designed with gas lift compressors, but because of the space limitation, the platforms can only accommodate a limited gas lift compressor capacity due to space constraints. Furthermore, in recent years, some of the fields just started with their secondary recovery i.e. water, gas injection where the fluid gradient became heavier due to GOR drop or water cut increases. With these limitations and issues, the team needs to be creative in order to prolong the fields’ life with various artificial lift. In order to push the limits, the team begins to improve gas lift distribution among gas lifted wells in the field. This is the cheapest option. Network model recommends the best distribution for each gas lifted wells. Gas lifted wells performance highly dependent on fluid weight, compressor pressure, and reservoir pressure. The change of these parameters will impact the production of these wells. Rigorous and prudent data acquisitions are important to predict performance. Some fields are equipped with pressure downhole gauges, wellhead pressure transmitters, and compressor pressure transmitters. The data collected is continuous and good enough to be used for analysis. Instead of depending on compressor capacity, a high-pressure gas well is a good option for gas lift supply. The issues are to find gas well with enough pressure and sustainability. Usually, this was done by sacrificing several barrels of oil to extract the gas. Electrical Submersible Pump (ESP) is a more expensive option compared to a gas lift method. The reason is most of these fields are not designed to accommodate ESP electricity and space requirements. Some equipment needs to be improved before ESP installation. Because of this, the team were considering new technology such as Thru Tubing Electrical Submersible Pump (TTESP) for a cheaper option. With the study and implementation as per above, the fields able to prolong its production until the end of Production Sharing Contract (PSC). This proactive approach has maintained the fields’ production with The paper seeks to present on the challenges, root cause analysis and the lessons learned from the subsequent improvement activities. The lessons learned will be applicable to oil fields with similar situations to further improve the fields’ production.

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