Hydrocarbon-Gas Cycling Improves Recovery in the Arun Gas Field
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Lean-gas injection has been used as an alternative method in gas fields to maintain reservoir pressure, minimize condensate banking near the wellbore, and mitigate oversupply operations during low-market periods. In this paper, past gas-cycling operations were examined to identify subsurface implications and effects on operability aspects for the Arun giant gas field offshore Indonesia in the North Sumatra Basin. Production and pressure data show that gas cycling contributes significantly to the improvement of field-recovery factors.
Reservoir and Fluid Description
The Arun gas field was discovered in 1971. The formation is carbonate reef, created during the Miocene age. It lies between two thick shale layers, Bampo on the bottom and Baong on the top. The Bampo formation is identified as source rock, with Baong shale as caprock. The field trends north to south, with a width of 18.5 km and a length of 5 km. Gas/water contact, to the south and west, was tilted toward the southern part of the field.
A gas-condensate reservoir at a depth of 10,000 ft was found to have an average thickness of 503 ft and an area of 21,450 acres, with 7,100-psig initial pressure and a temperature of 352°F. Initial condensate/gas ratio (CGR) was 50 bbl/MMcf. The reservoir has 16.2% average porosity and 17% initial water saturation. Volumetric original gas in place (OGIP) is calculated to be 17 scf. The current production rate from the field is approximately 80 MMcf/D with 2,400 bbl of condensate/day.
Fluid expansion and gas injection are determined to be the two main drive mechanisms on the basis of material-balance analysis. Hydrocarbon production uses four clusters with approximately 21 wells in each cluster. Each cluster is equipped with the same typical surface facilities. All produced fluid is pooled at Point A before being piped to gas-processing facilities. Initially, the produced gas was delivered to the Arun liquefied natural gas (LNG) plant for liquefaction but, in late 2014, the plant was shut down because of contract termination. In the second quarter of 2015, the facilities were reactivated for an LNG regasification terminal, Perta Arun Gas (PAG). Currently, the produced gas is transported to PAG for separation and dehydration before downstream processing.
The northern part of the field contains fair porosity; the middle part is dominated by good and fair porosity, while the southern part has a greater incidence of poor porosity. Clusters II and III, which are located at the middle part, contribute more cumulative gas production and condensate compared with Clusters I and IV. Thus, better reservoir properties and parameters are contributing to better production.
OGIP was first calculated using the ratio of reservoir pressure to gas-deviation factor vs. cumulative produced gas. This results in a calculation of 17 Tcf, excluding impurities, or equivalent to 20.73 Tcf in total. If the early trend is used, then calculations of OGIP may rise to 18 Tcf, excluding impurities, or equivalent to 22 Tcf in total. With a current total cumulative gas production of 20 Tcf, the latter estimation is more reasonable. Another method used is a plot of cumulative produced gas vs. wellhead pressure to estimate recoverable gas after an installation of a booster compressor for lowering the wellhead pressure. This results in a calculation of approximately 23 Tcf with 50-psi wellhead pressure. Because of the scale used, slight changes in extrapolation will result in huge volume differences. At the moment, the recovery factor is approximately 95%. Such high recovery is attributed to a combination of gas cycling, intensive infill drilling, and a pressure-lowering program. The produced gas contains methane (68.60%), ethane (5%), propane (2.5%), butane (4.41%), other heavier components (5.2%), and carbon dioxide (14.29%).
Gas cycling is the process of reinjecting some portion, or all, of the produced hydrocarbon gas into the reservoir. The intention is to produce more condensate while maintaining the reservoir pressure above the dewpoint. Initial hydrocarbon-gas reinjection officially started in the field in 1978. Fourteen gas downdip producers were converted into injectors. Most of them were drilled originally as producers before being converted into injectors. Total injection rate ranges from 40 MMcf/D to a peak of 0.9 Bcf/D.
The injectors were periodically checked for corrosion evaluation, fall-off tests, multirate tests, pressure surveys, and acidizing programs. Total injected gas over 20 years is 5.2 Tcf. Of this total, the southern part of the reservoir (Clusters III and IV) accounted for 4 Tcf, while the northern part (Clusters I and II) accounted for 1.2 Tcf. The peak gas-injection period came from 1990 to 1996. The water-rate plot imitates the gas-rate plot, which indicates that produced water mainly comes from the condensed water, not from the aquifer (Fig. 1). No significant aquifer influx is seen from the drive-mechanism plot. During injection, condensate production was maintained with a peak of 145,000 B/D in 1989. The maximum total replacement ratio was 0.7, which then stabilized at 0.4 before decreasing to 0.3. This indicates that all injected gases derived from the same field.
The main result of gas cycling can be observed both from condensate yield and water-to-gas ratio (WGR). During gas cycling, condensate yield is kept between 50 and 65 bbl/MMcf of produced gas in Clusters II and III. WGR was kept as low as 20 bbl/MMcf. Conversely, when gas cycling was stopped, WGR jumped to 100 bbl/MMcf. The indication of increasing WGR can be traced back to the point at which reservoir pressure is below dewpoint pressure. Thus, it can be concluded that gas cycling indeed improves condensate yields and delays producing water in the gas reservoir. It can be observed as well that Clusters II and III, which are located in the relatively higher position, experienced higher CGR and, therefore, benefitted more from gas injection. Condensate yield decreased after gas injection was ceased.
The gas-cycling facilities consist of gas-cooling systems, separators, and compressors. Three four-stage compressors were used to increase pressure from 1,100 to 7,100 psi. Two compressors were installed in Cluster III and one compressor in Cluster II. In 1984, the injection pressure was reduced to 6,100 psi and some modifications were made to improve the gas-injection rate from 170 to 255 MMcf/D/compressor.
The condensate and water were extracted immediately before gas was compressed and injected. Gas-cooling measures were added to the system to maximize condensate yield and improve compressor efficiency.
Gas injection/cycling provides additional energy to delay the decline of CGR, prevent condensate dropout in the reservoir, and delay the increase of WGR. Increasing water production is associated with more water vapor being carried by the gas after it loses condensate. CGR decline and WGR increase are significant when the reservoir pressure is less than the dewpoint pressure. Gas cycling should be started at an early stage when the reservoir pressure is still greater than the dewpoint pressure.
Gas-injection wells can be converted from producers in the downdip area instead of drilling a dedicated injector. The placement of injectors also can be exercised and optimized in the development plan. The Arun field is a good example of successful gas-cycling applications. The size, thickness, good properties, and lack of significant aquifer movement are some factors that contribute to the high recovery of hydrocarbons in the Arun field. In addition, effective reservoir management through gas cycling, intensive infill drilling, and lowering of the wellhead pressure are factors that improve ultimate gas recovery in the Arun field.
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Hydrocarbon-Gas Cycling Improves Recovery in the Arun Gas Field
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