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Since the industrial revolution, the oil and gas industry has played an important role in the economic transformation of the world, fueling the need for heat, light and mobility of the world’s population. Today, the oil and gas industry has the opportunity to redefine its boundaries through digitalisation, after a period of falling crude prices disrupted exploration and production activities, and ineffective mature field development challenges that are currently facing most oil and gas companies in Indonesia. The recent downturn in the oil and gas industry has led to massive layoffs. Digital industrial revolution is slowly changing how upstream businesses operate. Increasing public awareness of climate change has fuelled the urgency to shift to cleaner alternative energy.
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 brain of a waterflood project is a geological framework that defines reservoir continuity relative to its transmit fluids as well as restrict fluid movement. The lack of geological knowledge results in the misleading interpretation and understanding of the reservoir behavior. This paper presents an integrated geological aspect, concept and approach to design an effective well pattern and well spacing in waterflooding. This method is proven to improve sweep efficiency and lead us to make an EOR planning in our field. T Field is one of the mature fields where a successful waterflood project has been implemented in Indonesia
Detailed core description with sedimentary structure analysis, paleocurrent analysis in FMI data and various property maps were conducted to identify the relationship between injection and production well. It also gives the information about movement of injected water. The sediment transport suggests some directional anisotropy in permeability. The distribution of geological heterogeneities and their influence on fluid flow characteristics were determined by generating maps and cross sections based on integration of log, core & petrographic data and qualitative information from production data. Parameters mapped included the distribution of porosity, log derived geometric mean permeability, clay content, and Dykstra-Parsons coefficients of permeability variations.
The results of this study showed a good correlation of facies distribution and sedimentation direction with flow of water movement behavior. The direction indicated relatively west to east sediment transport being perpendicular to the structure. It was also matched with tracer survey analysis and simulation model. In our success story, we applied the staggered line of full scale waterflood pattern to maximize the areal sweep efficiency and improve 5-7% recovery factor of total OOIP. This information also strongly supports the building of reliable static and dynamic model.
We proved that an integrated geological approach, including a good understanding of facies and sedimentation characteristics of reservoir will lead us to build successful waterflood and EOR project in the future.
This course discusses the fundamental sand control considerations involved in completing a well and introduces the various sand control techniques commonly used across the industry, including standalone screens, gravel packs, high rate water packs and frac-packs. It requires only a basic understanding of oilfield operations and is intended for drilling, completion and production personnel with some sand control experience who are looking to gain a better understanding of each technique’s advantages, limitations and application window for use in their upcoming completions.
Aslam, B. M. (Institut Teknologi Bandung) | Ulitha, D. (Institut Teknologi Bandung) | Swadesi, B. (Institut Teknologi Bandung) | Fauzi, I. (Institut Teknologi Bandung) | Marhaendrajana, T. (Institut Teknologi Bandung) | Purba, F. I. (Pertamina EP) | Wardhana, A. I. (Pertamina EP) | Buhari, A. (Pertamina EP) | Hakim, R. (Pertamina EP) | Hasibuan, R. (Pertamina EP)
Tanjung Field is a brown field which pressure has already depleted and been supported by waterflooding for over a decade. To improve production, surfactant injection, is being studied to be employed in the field. The main objective of this study is to identify parameters that affect oil production increase. History match of the pilot test was carried out to improve the reliability of the reservoir model, hence improving the prediction result of surfactant injection forecast.
History match of the pilot test has been carried out using CMG STARS commercial simulator by considering mechanism inferred from laboratory evaluation such as wettability alteration, surfactant retention, interfacial tension reduction and improvement of mobility control due to lower oil-surfactant emulsion viscosity. These parameters are initially perceived from laboratory result, upscaling and adjustment is applied to field model to further on do sensitivity study. Sensitivity analysis of every parameter is provided to better understand the effect of each mechanism that contributes to the oil incremental result.
Stratigraphically, Tanjung Structure has 7 productive zones: Zone A, B, C, D, E, F and P. Reservoir Zone A has total estimated reserve of 193,732 MMSTB, with recovery factor of 16.3%. The zone consists of conglomerate sandstones with porosity of 21% and permeability ranging from 10 to 100 mD. The field produces light oil within 40 °API, 30% wax content and 1.14 cP of viscosity. T-119 is the well chosen to be injected due to its structural position that ease flow by gravity force to producer wells.
Forecast simulation based on coreflood result has been conducted for pilot test. However, the result was very pessimistic in predicting incremental oil gain and breakthrough time after compared to pilot result. An attempt to history match the surfactant flood pilot is presented by considering phenomena that is not included in the forecast based on additional lab and field data.
Tuesday, October 17 GP01 Opening Session Pecatu Halls 3 & 5 GP02 Executive Plenary Session: Energy Resilience through Efficiency, Collaboration and Technology Pecatu Halls 3 & 5 Moderator(s) Craig Douglas Stewart - PT. Medco Energi Internasional Speaker(s) Javier Rielo - Total E&P Asia Pacific, Christina Verchere - BP, Visal Leng - GE Oil & Gas Our industry has had to persevere a significant downturn over the last several years due to the drastic drop in oil and gas prices. To survive and thrive in this dynamic environment, and to continue to provide energy to our many stakeholders, the industry has had to transform itself and will need to continue to do so. This has and will need to be achieved through improved efficiency to create a sustainable operational blueprint, employing new strategies for collaboration between operators and the service sector and leveraging innovative technologies. This Executive Plenary Session brings together an esteemed group of industry players, representing the perspectives of National Oil Companies, International Oil Companies and major Service Companies, to discuss the achievements and outlook on this journey to energy resilience. Oil price have declined sharply since 2014.
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.
SN Structure is one of structure in the oil & gas rich Kutai Basin of East Kalimantan, Indonesia. Since, well SN-1 was drilled then plugged (with oil shows) and SN-2 has just been drilled with target on the Pelarang anticline situated approximately 2.6 kms southeast of SN-1 then plugged and temporary abandoned. The primary objective of SN target was the shallow updip potential of the Late Miocene Balikpapan and Early-Middle Miocene Pulau Balang reservoirs.
In other well, SN-2 the target was 2,355 ftMD vertical well. On 12-1/4″ Open Hole section, there was gas peak and high pressure on depth 475-482 ftMD with MW slightly reach the LOT on last 13-5/8″ casing. While drilling there was a deals with well kick condition that should occurs with MW slightly reach 18 ppg (Last LOT reading). Occurs the kick, gas came out from separator then burnt out. For safety, it has to stop and set the casing 9-5/8″ to depth 738 ftMD, without DST activity. Further now, the SN structure has just shown that it has potential hydrocarbon on its subsurface which need more proven data to get the P50 and P90 for its structure.
Next 8-1/2″ open hole section, the operation must face the well with MW 17.1 ppg which with additional surface pressure, it slightly reach the MW LOT 18.2 ppg. At depth 1,170 ftMD, with MW 17.2 ppg there was kick and well control problem and for safe safety operation reasons, drilling finnaly has to stop. Then it was plugged from depth 1,170 ftMD to depth 738 ftMD and temporary abandonment, caused the MW to occurs the kick and well control has reached 17.6 ppg. On plan program, there is an open hole logging job to indicate and collect data on 8-1/2″ section. But the program cancelled just because the slurry and viscous of MW is very high and the tools can't go down deep to the target depth. SN-2 well now has suspended operation and there is no Testing operation on Well, with gas Hydrocarbon indications. For future, this well is planned for DST job on section depth 315 – 738 ft MD. Further now, the SN structure has just shown that it has potential hydrocarbon on its subsurface.
Its structure is more challenged caused there highly gas peak and some section must occurs kick and well control while drilling. This might caused by fault which acting as a seal, and has been used as a boundary for the P90 area used in the calculation of reserves for the SN-2 Prospect. Its structure must have some G&G studies for having some good parameter and indication, while drilling operation team must have a good design on well schematic and drilling program for the next well on SN structure. Which means have a good and perform of Drilling contractor and materials.
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).