Hydrocarbon-Gas Cycling Improves Recovery in the Arun Gas Field
- Chris Carpenter (JPT Technology Editor)
- Document ID
- Society of Petroleum Engineers
- Journal of Petroleum Technology
- Publication Date
- November 2018
- Document Type
- Journal Paper
- 89 - 90
- 2018. Society of Petroleum Engineers
- 6 in the last 30 days
- 68 since 2007
- Show more detail
- View rights & permissions
|SPE Member Price:||Free|
|SPE Non-Member Price:||USD 17.00|
This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 186280, “Review of 20 Years of Hydrocarbon-Gas Cycling in the Arun Gas Field,” by Suhendro, SPE, Pertamina Hulu Energi, prepared for the 2017 SPE/IATMI Asia Pacific Oil and Gas Conference and Exhibition, Bali, Indonesia, 17–19 October. The paper has not been peer reviewed.
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.
|File Size||423 KB||Number of Pages||2|