Intermittent Gas Lift Used in Hydrate Mitigation and Flare Reduction in Algeria
Hassi Messaoud is a mature oil field with more than 1,100 production wells. Approximately half of the wells are natural flow and the other half use continuous gas lift (CGL) with concentric (CCE) strings.
Hassi Messaoud is a mature oil field with more than 1,100 production wells. Approximately half of the wells are natural flow and the other half use continuous gas lift (CGL) with concentric (CCE) strings. To reduce the usage of the high volume of lift gas, intermittent gas lift (IGL) was selected in a pilot project to evaluate its applicability in the field for wells characterized by high gas/oil ratio (GOR) and without continuous concurrent water injection (with lift gas) to dissolve salt deposited downhole.
Field production began in 1957. During the first 20 years, all production wells were naturally flowing; in 1980, gas lift was introduced into the field development and has remained the only artificial-lift method. Electrical submersible pumping systems have been introduced into the field recently. Of the production wells, 795 are flowing while 376 are shut in for a variety of reasons. Among the flowing production wells, 409 are naturally flowing and 386 are artificial-lift wells.
Production fluids are processed by 25 separator stations throughout the field. Gas usually is compressed first at the satellite level; then, at the central processing facilities, the gas is further compressed to the pressure required for injection into the reservoir. Water is treated by the addition of surfactants. The treated water is pumped into the water-injection network to be used in both reservoir-pressure maintenance and salt wash in wells.
In the field’s first years, the oil-production rate increased quickly as the number of wells grew. Since 2007, oil production has declined quickly in naturally flowing wells. The steady increase in oil production from gas-lift wells offset the fast production decline in the full field. However, the oil production from gas-lift wells has leveled off during the past 2 years, while the production from naturally flowing wells recovered slightly. The gas lift wells contribute approximately 40% of the field production.
Combined Gas Network for Reservoir Gas Injection and Gas Lift
A specific challenge of the Hassi Messaoud field operation is the highly complex gas network, in which the gas-lift network is attached to the gas-injection network for reservoir-pressure maintenance. The gas lift was grown organically out of the reservoir gas-injection network. Initially, when only a small number of wells needed gas lift, this approach might have been cost-effective, but the increasing number of gas-lift wells meant that different methods had to be considered.
Wells are located at different distances from each gas-lift manifold. When a well is farther away from a gas-lift manifold, its injection pressure may be low and its injection rate may not be sufficient for effective lifting. Conversely, the wells closer to the manifolds or closer to the let-down station have higher gas-injection pressure and higher lift-gas injection rates. Wells with relatively low production rates (less than 2 m3/h) represent 48% of total active wells. These wells produce only 20% of the total production by all gas-lifted wells, yet they use 45% of the lift gas injected.
Whenever the total gas rate from a gas-lift well becomes high in the judgment of the operator (in comparison with the other gas-lift wells), the well is shut off and usually remains offline for a significant time, if not permanently. By shutting-in these wells, the operator blocks the excessive gas from the production system to eliminate the need to flare at the separator level. However, if the total gas in the full system can be managed effectively to reduce the total gas, some of the shut-in wells with higher oil rates before their shut-in could be reactivated to produce a reasonable amount of oil.
Hydrate formation in the lift-gas injection lines has caused significant production losses during winter months in the field. These losses have taken place despite the use of different mitigation techniques. Fig. 1 shows an instance in which the outside of the gas-injection line downstream of the gas-lift injection choke is covered by ice. The ice on the pipeline was formed when the temperature inside the gas-lift line decreased because of the Joule-Thompson cooling effects caused by the pressure drop across the gas-lift injection choke. The low temperature inside the gas-lift line caused the wet gas inside to form hydrate or ice. The hydrate inside the pipe restricts lift gas from being injected into the well.
IGL Pilot Test Case 1: Well MD41
Well MD41 was drilled and completed in August 1960. It was switched to gas-lift operation in late 2011. The well produces less than 1 m3/h, with an average GOR of 3800 sm3/sm3. In CGL operation, lift gas is injected into the well through the 1.9-in. concentric line. The reservoir fluids enter the 4½-in. production liner to the end of the 1.9-in. concentric string and are mixed with the injected lift gas. The mixed fluids are produced to the wellhead through the annulus between the concentric string and the production tubing.
When the well is in IGL mode, the lift gas is injected in a cyclical manner and a large volume of lift gas is injected into the well during a predetermined short time period. The gas slug pushes the liquid slug to the surface. Lift gas is stopped and the remaining liquid in the annulus falls back to the bottom of the well to join new liquids fed from the reservoir to build up the next liquid slug. When the new liquid slug reaches a predetermined height, the lift gas is injected into the concentric string again and a new intermittent cycle repeats.
The objective of the first IGL trial was simply to test the applicability of this artificial-lift method in wells completed with a CCE string. The test sequence was aimed at
- Finding the optimal injection rate to assure the displacement of the liquid slug to the surface with minimum liquid fallback, and to avoid using excessive lift gas, which could cause fluctuations in the separator and network system
- Monitoring the wellhead pressure during the displacement of the liquid slug
- Monitoring the pipeline pressure
- Monitoring the time required to displace the total liquid slug to the surface, which helps in optimizing gas-injection time
Observations from the pilot test of IGL operations in Well MD41 included the following:
- During slug displacement, the wellhead pressure reached 40 bars, while the pipeline pressure remained at approximately 20 bars. The high wellhead pressure negatively affected liquid slug recovery.
- At the start of gas injection, the gas-injection pressure was 20 bars. It took between 4 and 6 minutes to reach 100 bars. This was the time required to fill the concentric string with lift gas.
- The liquid slug took 14 to 16 minutes to reach the surface. Afterward, 30 minutes of gas injection were required to displace the liquid slug from the wellbore to the surface flowline. This significant length of time resulted from the presence of production choke.
- The observed optimal lift-gas injection rate during the injection period was approximately 120,000 std m3/d for this well.
- Any lift-gas rate during the injection period of less than 90,000 std m3/d could not displace the liquid slug to the surface. However, any lift-gas injection rate greater than 120,000 std m3/d would result in excessive lift gas to be injected.
The lift-gas temperature after the lift-gas choke during IGL was 39°C, while the temperature was 31°C during CGL. The temperature remained fairly high throughout the IGL cycle. This is an important feature of the IGL operation—it can help avoid one of the most difficult challenges encountered in the Hassi Messaoud field: formation of hydrates in the gas-lift lines, especially during the cold winter months.
Two other pilot tests of IGL on wells previously operated with CGL are discussed in detail in the complete paper.
The pilot program using IGL in concentric strings in the Hassi Messaoud field achieved the desired objectives. The program proved that IGL is a viable, effective artificial-lift method for the field. Application of IGL in this field has the following advantages:
- Reduction of the lift-gas injection rate
- Reduction or elimination of the potential for hydrate formation in the gas-lift line during the cold season
- Slight to moderate increase in oil-production rates
Even though gas-lift completion in the field is not conventional, it was possible to deploy IGL in the existing well completions. The average oil production gain for the three trial wells was 17%, while the average lift-gas-rate reduction for the wells was 30%.
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191542, “Hydrate Mitigation and Flare Reduction Using Intermittent Gas Lift in Hassi Messaoud, Algeria,” by Ala Eddine Aoun, SPE, Faouzi Maougal, and Lahcene Kabour, Sonatrach, and Tony Liao, SPE, Brahim AbdallahElhadj, and Sabrina Behaz, Halliburton, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed.