Gas Lift Increases High-Volume Production From Claymore Field
- Edward E. DeMoss (Teledyne Merla) | W. David Tiemann (Occidental Petroleum (Caledonia) Ltd.)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- April 1982
- Document Type
- Journal Paper
- 696 - 702
- 1982. Society of Petroleum Engineers
- 2.2.2 Perforating, 5.4.2 Gas Injection Methods, 4.5.7 Controls and Umbilicals, 6.5.2 Water use, produced water discharge and disposal, 3 Production and Well Operations, 4.1.2 Separation and Treating, 3.1 Artificial Lift Systems, 2.4.3 Sand/Solids Control, 3.1.6 Gas Lift, 5.5 Reservoir Simulation, 5.2.1 Phase Behavior and PVT Measurements, 4.1.5 Processing Equipment, 1.6 Drilling Operations, 4.2 Pipelines, Flowlines and Risers, 4.1.6 Compressors, Engines and Turbines, 5.7 Reserves Evaluation, 5.6.4 Drillstem/Well Testing
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The selection of gas lift for the Claymore A platform has produced desired results. Gas lift has allowed the operator to respond quickly to changing well conditions at small cost. The flexibility of gas lift and the ease of installing valves by wireline have been very profitable features of the system. During a 3-month period in the last half of 1978, gas-lift valves were wirelined into enough wells to almost double the platform oil production from 55,000 to 93,000 B/D (8744 to 14 786 m /d). The production increase was caused by moving the point of gas injection down from Station 1 to Station 5. Drilling is still active, with 24 wells completed by Nov. 1981. Currently, the total gas-lifted fluid production is more than 100,000 BFPD (15 899 m /d fluid) with 18 wells being gas lifted. Claymore is being reviewed to optimize producing well locations and utilize more slots for production by installing subsea water injectors. Once this program is completed, 25 wells or more will be gas-lifted.
Current production operations on the Claymore A platform have resulted from cooperative efforts of reservoir and production personnel. Early in the development of Claymore field, reservoir simulations were run to estimate PI's of the wells and to determine reserve estimates. This work exposed the need for a pressure-maintenance program. So, during the first year, water injection into the reservoir was begun. This was done early to eliminate (or to reduce substantially) a big drop in the static reservoir pressure. Without water injection, a 20% drop in static reservoir pressure was expected during the first year, and with PI's ranging from 5 to 36 B/D-psi (0.115 to 0.830 m /d kPa), it was essential that an artificial-lift system be selected and implemented as soon as possible. Since the formation GOR of the Claymore was low, gas lift could reduce the flowing bottomhole pressure (BHP) substantially and increase the field's production rate. Even though the formation GOR was low, it was enough to supply fuel for the platform and circulated gas for lifting the wells. The gas for platform fuel needs is taken from the low-pressure manifold. A gas line from the Piper field furnished make-up gas to the compressor suction gas header. At first, the Piper gas was used only at special times. But the need for Piper gas increased each month and a daily requirement was established. In May 1978, the average daily use of Piper gas to the Claymore was about 4.2 MMscf/D (120 273 std m /d). The availability of Piper gas, therefore, played an important role in the selection of gas lift to produce the Claymore. A detailed study of the capability of gas lift produced the conclusions and design conditions in Table 1. Note that 1,850 psi (12 755 kPa) is the gas-lift surface-injection pressure at the well. A 1,600-psi (11 032-kPa) surface gas pressure was studied but not selected. With the BHP's and PI's expected, 1,850 psi (12 755 kPa) was more economical and more effective in generating the needed drawdown at the wellbores. The individual well designs were based on three deviation angles: 20, 40, and 60 deg. All wells had 5 1/2-in. (13.97-cm) tubing with 9 1/8-in. (24.45-cm) casing. Note also that, even though most wells now are producing clean oil and some are cutting more than 30% water, the designs are based on 50 % water and 12,000 BFPD (1908 m /d fluid). This was done because the reservoir simulation predicted a rapid water breakthrough to the producing wells. In fact, the water cut rose to 85 % on Well C6 in Sept. 1981. A typical graphic design is shown in Fig. 1 for a well with 40 deg. deviation. Equipment needs were defined and purchased from these preliminary designs.
Equipment Selection and Technology
Special efforts by the production engineering group were conducted to ensure gas lift success. Three well-known two-phase gradient curves were studied and compared with actual flowing conditions at Claymore and at Piper.
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