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.
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.
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.
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).
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.
Drilling horizontal wells in soft formations can pose significant risks that require careful planning and execution. During 2014, Virginia Indonesia Co. Limited (Vico) successfully completed two surface-toinseam horizontal wells to appraise coalbed methane (CBM) production potential on their Sanga Sanga license in East Kalimantan, Indonesia. Both wells passed through soft shales and coals that exhibited breakouts in offset wells, in addition to heavily depleted zones exhibiting large fluid losses in an area well known for shallow gas blowouts. Geomechanical analysis of information from nearby offset wells was used to determine the mud-weight window and fluid properties required to effectively manage these conditions. The results were incorporated into the preliminary well design and planning, and with model matching carried out in real time while drilling operations were underway, any deviations in wellbore integrity were managed as they arose. The drilling success was, in large part, a result of extensive preplanning and a regimented approach to how the wells would be drilled and any instability dealt with promptly. In addition, real-time monitoring that identified deviations from model-based predictions provided invaluable information for planning subsequent wells. The methodical approach to planning and execution of these wells led to their successful completion, with the results potentially reshaping the Indonesian CBM and energy industry.
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
The Coalbed methane reservoir in Barito basin, Indonesia may be stimulated by hydraulic fracturing to efficiently recover methane gas from low permeability reservoirs. The permeability of coalbed may be quite diverse ranged up to a few thousands mD. If the reservoir permeability is too low, less than tenth md, hydraulic fracturing could be considered to improve gas productivity as stimulation treatment method. In this study, hydraulic fracturing treatment design is conducted to determine total slurry volume and proper pump rate upon different fracture lengths. To set optimal treatment schedule, fracture geometry and fracture efficiency was compared depending on increase of fracture length and pump rate by fracturing stages. The more pump rate increased the more slurry volume and fracture efficiency increased when maximum fracture length was fixed, respectively 200m, 300m and 400m considering well spacing, etc. The proper pump rate was determined to 40bpm results from high fracture efficiency. In addition, total slurry volumes were decided to each 18,630U.S gallon for 200m fracture length, 50,751U.S gallon for 300m, and 105,717U.S gallon for 400m. Furthermore, usage of proppant was determined using definite proper pump rate and slurry volume determined by highest pump rate in this study. All calculated fracture lengths of treatment with proppant are shorter than fracture length of treatment without proppant and also fracture widths and heights are larger than treatment without proppant. However each of fracture efficiency in treatment with proppant was higher than that in treatment without proppant. Therefore proppant would contribute to improve the fracture efficiency of hydraulic fracture treatment in Coalbed methane reservoir, Barito basin. Consequently, 3D propped fracture model was designed for the coalbed methane. Developed hydraulic fracturing model would be useful for hydraulic treatment of coalbed methane especially in Barito basin for fracture design and treatment analysis prior to the actual treatment.