Installation of Gas Ejector Provides Boost to Low-Pressure Gas Well
To further reduce backpressure on low-pressure gas wells and increase reserves in a mature gas field, a gas-ejector project was evaluated and proposed.
To further reduce backpressure on low-pressure gas wells and increase reserves in a mature gas field, a gas-ejector project was evaluated and proposed. Following on-site tests on several gas wells, the gas ejector was put into service successfully. Reservoir simulation estimates that 6.4 Bcf of incremental reserves will be achieved through gas-ejector installation by decreasing inlet pressure to 50 from 100 psi. The application of the gas ejector during a 2-year period to reduce backpressure has helped to improve economics in a mature gas field.
The YC13-1 gas field commenced sales from offshore platforms to Hong Kong and Hainan Island in 1996. Following 22 years of continued production, the field depleted naturally to approximately 10% of the original reservoir pressure, with most wells producing with tubing pressure varying from 150 to 200 psi. The field is underlain by a relatively small water aquifer, which has caused water cut to increase marginally in a few wells and has affected performance in lower-pressure gas wells. The installation of a gas injector helps to reduce backpressure on producing wells, thus providing more energy to lift water from the wellbore.
An ejector is a device used to induce a secondary fluid by momentum and energy transfer from a high-velocity primary jet. Ejectors can be operated with either incompressible fluids or compressible fluids, such as gas or vapor. The working process for the gas ejector and jet pump are the same except for a supersonic, choked-flow nozzle used in a gas ejector. High-pressure gas at the primary inlet is accelerated to high velocity through a converging/diverging supersonic nozzle. The pressure from the primary fluid at the inlet is converted partially to momentum at the nozzle exit based on Bernoulli’s equation. The high-velocity and low-pressure primary jet induce a secondary flow, and the two streams combine in the mixing chamber to transfer the energy. A diffuser is usually installed at the exit of the mixing chamber to lift the pressure of mixed flow. Fig. 1 shows a cross-sectional view of a typical gas ejector.
The gas ejector has several advantages over installation of additional compression. The gas ejector is a low-cost solution, occupying a small area with low weight, which is advantageous in offshore platforms. No moving parts exist, so operating cost is minimal. The gas ejector can maintain a stable output pressure with the flexibility to vary rates.
The gas-ejector design was conducted according to offshore production requirements, with design parameters summarized in Table 1 of the complete paper. A distributed control system (DCS) is required to adjust the nozzle opening depending on pressure and volume from the secondary fluid and to make sure the output pressure from the gas ejector is stable and the entrainment ratio is optimized. A pressure gauge and a transmitter are installed in the outlet pipe, and the pressure signal is sent to the DCS. The DCS will enable a pneumatic actuator, adjusting the opening of the nozzle to ensure that the output pressure can reach the set value.
To ensure the cost effectiveness of the gas-ejector project, existing facilities on the YC13-1 platform were fully involved and a test separator was used as a surge vessel to stabilize the flow to the gas ejector and remove water from the wellstream. The design takes advantage of existing high-pressure gas discharged from the dry gas compressor to work as the primary fluid, and, consequently, no additional operating costs for the primary fluid are incurred. To eliminate the chance of forming hydrates, optimization steps were undertaken. The structure and location of the nozzle and the secondary fluid absorption port were designed to ensure quick and uniform heat exchange between the dry gas and secondary fluid.
Field tests on the gas ejector were conducted to ensure the design would meet the requirements for a safe and efficient operation. Well A5, which represents the working condition of the secondary fluid of the gas ejector, was connected to the gas ejector to perform the initial test. The test result shows a pressure increase across the gas ejector from 38 to 71 psia, with the entrainment ratio close to 50%.
The test on Well A13 was conducted to check the performance of the gas ejector at the condition of the lower secondary fluid supply. The results show the gas ejector can work properly in this condition even though the entrainment ratio is lower than the targeted level of 30%. The gas rate from Well A13 was increased to 3.7 MMscf/D from 2.2 MMscf/D, and backpressure reduced to 40 psi.
The overall performance of the gas ejector for Wells A13 and A5 is illustrated in Fig. 2. Both wells were put through the gas ejector to minimize the chance of well shutdown caused by excessive water. Approximately 4 Bcf of additional gas eventually was produced through the gas ejector from these two wells, and no gas hydrate formation was observed.
Backpressure could be lowered to 40 psi and additional reserves of 6.4 Bcf could be gained through application of a gas ejector in the YC13-1 field. Cost effectiveness and good economics can be achieved for the gas-ejector project by fully using existing facilities, high-pressure recycled gas, and domestic equipment. The gas ejector was tested successfully in both high- and low-performance wells, with test results showing that the gas ejector can accommodate varying well conditions to ensure a stable output pressure. The gas ejector was applied to the unloading of low-pressure wells with high water/gas ratios and maximized gas recovery from wells.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 196440, “Giving a Boost to a Low-Pressure Gas Well by Installing a Gas Ejector,” by Ping Wei and Brian Macdonald, SPE, KUFPEC, prepared for the 2019 SPE Asia Pacific Oil and Gas Conference and Exhibition, 29–31 October, Bali, Indonesia. The paper has not been peer reviewed.