PETRONAS FLNG SATU (PFLNG1) is a floating liquefied natural gas facility producing 1.2 million tonnes per annum (mtpa) of LNG, on a facility that is 365m long, and 60m wide, making it among the largest offshore facility ever built. The PFLNG1 project is the first of its kind in the world and is the first deployment of PETRONASâ€™ Floating Liquefied Natural Gas (FLNG) technology, consolidating the traditional offshore to onshore LNG infrastructure into a single facility. This will see a giant floating facility capable of extracting, liquefying and storing LNG at sea, before it is exported to customers around the globe. The FLNG journey has come a long way since 2006, with many technological options explored to monetise and unlock the potential of small and stranded gas fields. Moving an LNG production to an offshore setting poses a demanding set of challenges â€“ as every element of a conventional LNG facility needs to fit into an area roughly one quarter the size in the open seas whilst maintaining safety and increased flexibility to LNG production and delivery. The keynote address describes the breakthrough features of PFLNG1 â€“ the worldâ€™s first floating LNG facility; and the pioneering innovation that it brings to the LNG industry.
Nugroho, Bayu (Ophir Energy Indonesia) | Guritno, Elly (Ophir Energy Indonesia) | Mustapha, Haryo (Ophir Energy Indonesia) | Darmawan, Windi (Ophir Energy Indonesia) | Subekti, Ari (Ophir Energy Indonesia) | Davis, Carey (Ophir Energy Indonesia)
The long-held view and general understanding on the source rock within the Upper Kutai Basin is that it comes from the fluvial-deltaic facies. This deltaic coals and carbonaceous source rock has been proven generating gas with oil in Western Indonesian tertiary basins such as the Miocene Balikpapan Formation in the Lower Kutai Basin, Tanjung Formation in the Barito Basin and TalangAkar Formation in the South Sumatra Basin. The Oligocene carbonate play in the Upper Kutai Basin is under-explored, with exploration historically focusing on the Miocene deltaic and turbidite plays. These carbonates mainly consist of the UjohBilang or Berai equivalent Formation which outcrops along the southern and western margin of the basin, and is seismically imaged in the subsurface, forming on isolated basement highs and large platform areas. Ophir Energy's Kerendan Gas Field in the Bangkanai PSC is the only Oligocene carbonate gas producer in the Kutai Basin. Development drilling on the Kerendan Field and the West Kerendan-1 exploration well has provided new information which, together with a reevaluation of the existing carbon isotope and other geochemical data has led to a reinterpretation of the source rocks for Kerendan gas. The gas was previously postulated to be generated from Eocene terrestrial source rocks similar to the source rocks that generated oil and gas in the neighboring Tanjung Field in the Barito Basin, 100 kms to the South. The recent carbon isotope data from the Kerendan wells reveals that the gas in the Oligocene carbonate reservoir in Kerendan was generated from a marine source rock and is not terrestrial in origin. In addition there is also a terrestrial component within the gas found at the younger stratigraphic interval.
ABSTRACT: The study is conducted in a coal mining which elongated at South Kalimantan to East Kalimantan covering Tanjung Formation and Kampungbaru Formation. As the area is an open-pit mine, a rapid assessment is required in order to determine slope stability. One of the assessment methods is by using SMR (Slope Mass Rating) based on Bienawski’s RMR. SMR has been studied and formulated by a lot of researchers. However, those SMR results might be inappropriate for some field condition, including the study area. Therefore, in order to get the optimal value of SMR, a correction must be done to all value of obtained SMR. The correction provides modified SMR formula as follow: SMR = 7.2251 RMR0.5207; R2 = 0.89. Based on the formula, slope stability can be determined and applied to slope design for rock slope with following criterions: (1) Very poor rock: slope will stable with dip-slope <35°; (2)Poor rock: slope will stable between 35°-49°; (3)Fair rock: slope will stable between 50°-61°; (4) Good rock: slope will stable between 61°-71°; (5) Very good rock: slope will stable between 71°-79°.
The research area is an open-pit mine, a rapid assessment is required in order to determine slope stability. One of the assessment methods is by using SMR (Slope Mass Rating) based on Bienawski’s RMR (Rock Mass Rating). Slope Mass Rating is a method that can provide quick suggestion for determining stable slope angle in mining engineering (open-pit mining). Some researchers proposed different formulas of SMR, therefore to get optimum value of SMR, an approach was carried out through modification (Zakaria et al. 2015). Geomechanics classification is based on Rock Mass Rating (Bieniawski, 1989). The study is conducted in a coal mining which elongated at South Kalimantan to East Kalimantan covering Tanjung Formation and Kampungbaru Formation. Tanjung Formation at Satui and surrounding is located in South Kalimantan, and Kampungbaru Formation at Sangasanga located at East Kalimantan (Fig. 1).
Putra, Rieza R. (Pukesmigas Trisakti University) | Larasati, Dian (NEGT Pertamina Upstream Technology Center) | Ardi, Sunarli (NEGT Pertamina Upstream Technology Center) | Fiqih, Fikri Muhammad (Pertamina Hulu Energi) | Ramdani, Hilman (Pertamina Hulu Energi) | Widarto, Djedi (NEGT Pertamina Upstream Technology Center) | Guntoro, Agus (Pukesmigas Trisakti University) | Usman, Alfian (NEGT Pertamina Upstream Technology Center)
Integrated from regional studies, geomechanical test from WCBF outcrop sample, conducted to determine where exactly placement of effective coal cleat accumulation. However, this paper focusly on structural and geomechanical aspect and which deformation phase that causing effective cleat accumulation.
Macroscale approach based on three stopsite of WCBF obtained major of west-east trending face cleat and north-south trending of butt cleat. The major trend of coal cleat respectively correlate with regional west-east shortening deformation phase due to tectonic inversion by Meratus Mountain during pliocene-pleistocene. Number of permeability value based on macroscale technique using outcrop matchsticks and cubes formula run widely in 7-46 darcy interval. Mesoscale approach using FMI analysis shows similar west-east coal cleat in subsurface (Coal Zone A) and strongly correlate with downward coal zone (B and C). Permeability value of mesoscale technique at 7.05 md and 5.2% of porosity based on CT Scan analysis from WCBF outcrop sample (TJ-11). The value of mesoscale permeability shows good negative exponential relationship through subsurface permeability test using IFO Test from 414-616 m of depth with range of permeability 3.3-0.23 md. Microscale measurement using SEM analysis from TJ-09, TJ-10, TJ-11 have values range from 0.6, 18.53, 17.824 md. As tested by mesoscale permeability integrated to IFO Test, each of approximation parameter would be respectively following the mesoscale exponential power law.
Geomechanic test was directly tested to SPL-03 sample from WCBF shows number elastic moduli; Young Modulus at 2652.74 MPa, Bulk Modulus 1163.48, Poisson Ratio 1069.65. Hydrostatic crossplot between depth against pressure (confining pressure from uniaxial test) clearly shows that overburden stress (SV) have no influence to create effective stress-driven cleat prior to deformation (Shmax and Shmin).
Fault Facies gave a brief classification of the area surrounding the fault which accomodate most effective cleat abundance in damage zone of the fault. Using weight factoring correlation between paleogeographic and strain partitioning by observe the geometry changing between bisected σ1 and σ3 trajectories. The most effective types of cleat occurs in distributed conduit and combine conduit barrier fault area with tensional-rotational and contractional-rotational strain region.
Puji Astuti, Tri Rani (U. Gadjah Mada) | Surjono, Sugeng Sapto (U. Gadjah Mada) | Warmada, I Wayan (U. Gadjah Mada) | Kusuma, Didit Putra (U. Gadjah Mada) | Tsukada, Yasumoto (Hokkaido U.) | Otake, Tsubasa (Hokkaido U.) | Sato, Tsutomu (Hokkaido U.)
The Middle – Late Eocene sandstones of Batu Ayau Formation have been examined for the potential as a reservoir based on subsurface data and outcrop samples taken along Ritan and Belayan’s River. Petrographic study, XRD, SEM/EDS, porosity measurement, and quantitative determination of reservoir properties were carried out in this study. The sandstones are fine- to coarse-grained, moderately well to well sorted litharenite with subordinate lithic arkose, subarkose, sublitharenite and feldsphatic litharenite. The framework compositions of all sandstones are entirely quartz and plagioclase with trace amounts of K-feldspar and muscovite. The diagenetic processes include compaction, cementation, overgrowth of autigenic minerals (smectite), and dissolution due to alteration of feldspars. The SEM photomicrographs exhibit four types of cement such as mordenite, kaolinite, smectite and overgrowth quartz which are present over the entire samples. Quartz and kaolinite occur as pore-lining and pore-filling cements which locally developed as vermiform and accelerated the minor porosity loss due to pore-occlusion. Result of XRD analysis for the whole work are consistent with the qualitative result of petrographic analysis. Result of XRD analysis with ethylene glycol solvation for clay fraction (<2 µm) indicate a progressive alteration of smectite to illite. Based on the Watanabe’s Diagram, the presence of smectite layers in interstratified illite/smectite continously decrease from 100% to 65% with increasing the burial depth. The result indicate that the paleotemperature for sandstone diagenesis around 60-90°C. This is interpreted to be the result of temperature controlled chemical compaction, i.e. transformation from smectite to illite, feldspar dissolution and quartz precipitation. The laboratory analysis as well as field data demonstrate the sandstones of Batu Ayau Formation were subjected to mesodiagenesis and result in good to tight ranges of porosity.
Keyword: sandstone reservoir, Batu Ayau Formation, diagenesis, smectite, illite
Upstream oil & gas sector commonly generate oily sludge wastes. This waste can be treated with many methods according to the technical-economic assessment. Recently, co-processing technology usually being chooses in Indonesia. Therefore we need to evaluate co-processing in the legality, technique and economic aspects as the treatment option in Indonesia. The use of co-processing technology as Alternative Fuel and Raw Materials AFR) in cement industry can be implemented into 3 categories, i.e. co-processing of waste, alternative raw materials and mineral components. According to the legality assessment, co-processing comply with Ministry of Environment (MOE) requirements in utilization license because there are three cement industry licensed by MOE, minimal waste heating value 3,000-7,000 kKal/kg (above 2,500 kKal/kg or 4,500 BTU per lb) and controllable emission quality. At the technical aspect, co-processing can be execute easily, fast, practically and total solution (no slag and bottom ash) with no long term liability for the generator. Oily sludge wastes only need to be handling/packing and then transport to the Collector/Profiteer, treatment less than one month for a thousand ton of wastes and wastes actually destroyed without any residue. At the economic aspect, co-processing approximately costs about U$ 80-170 per ton. This cost is more competitive than other methods. Beside that aspects, co-processing give ecological benefits as a waste recovery and decrease the cement industry emission rate. Finally, co-processing is decent to be considered as the main option for oily sludge treatment according this study.
This paper will detail how a mature oil field in the South Kalimantan region of Indonesia was revitalised by the use of hydraulic fracturing. The Tanjung Raya field is a complex, multilayered, mature oil field. This field was initially developed in the 1960's, with production peaking at over 55,000 bopd. By the mid 1990's, production had declined to less than 1,200 bopd. The introduction of a water flood increased production to a peak of 10,000 bopd, but this quickly declined at an average rate of circa 33% per year. With the introduction of a fracturing programme, based on treating existing and new wells, production has been maintained at a flat 7,000 bopd over the past two years. The hydraulic fracturing program has accounted for 80% of these significant production gains, adding more than 5.7 million barrels of recoverable reserves and extending the economic life of the field by more than 2.5 years.
Hydraulic fracturing is a process that is relatively underutilised in the Asia-Pacific region, as compared to North America, Latin America and the Middle East. With a couple of recent noticeable exceptions, the technique is either not considered during field development and redevelopment, or it is used on a one-off, remedial basis. However, fracturing can be an integral part of well design, and an effective tool when the technique is applied systematically by practitioners who understand its capabilities; as demonstrated in the Tanjung Raya field.
This paper will discuss how a significant increase in oil productivity from a mature field was attained with a very high propped fracture treatment success rate. It will also detail how the correct design of fracture treatments can enhance reservoir recovery rates, and fully utilise vertical wells as a low cost, effective alternative to horizontal wells, or to increase well spacing. The paper will also discuss the most significant issues of implementing such a program and how these issues were effectively dealt with in the Tanjung field.
Indonesia has thick, low-rank coal deposits that are prospective for coalbedmethane (CBM) development but remain untested. Conventional oil and gas wellsthat drill through these coal seams experience gas kicks and blow outs, goodCBM indicators. We analyzed petroleum and coal mining data to perform acomprehensive assessment of Indonesia's CBM resources. We identified 12.7trillion m3 (450 Tcf) of prospective CBM resources within eleven onshore coalbasins. Full-cycle development costs in high-graded areas are estimated at$0.70/Mcf. These potential CBM reservoirs could be tested at low cost usingcoreholes or production "wells of opportunity."