Complex hydrocarbon distributions where reservoirs are filled by oil and gas phases with different densities and genetic types interfingering within a basin are a common phenomenon in Southeast Asia and are often attributed to vertical migration. Attempts to understanding the controlling factors of vertical hydrocarbon migration by modeling the hydrocarbon charging and entrapment history from two Cenozoic basins in Southeast Asia—West Java and the Madura Platform—are discussed.
A modified invasion percolation algorithm was used to simulate the secondary migration models, which follows the principle that migration occurs in a state of capillary equilibrium in a flow regime dominated by buoyancy and capillary forces. Three-dimensional (3D) seismic data were used as the base grid for migration simulation to capture the effect of both structure and facies variations on fluid flow.
Two models, one from the West Java Basin (fault-bounded structure) and the East Java Basin (nonfault-bounded structure), are presented. For both cases, interfingering between oil and gas occurred, with most oils trapped within the lower formations, a mixture of oil and gas dominates the middle formations, and mostly gas in the upper formation. These vertical arrangements are possible because of the relatively weak formational seals within the basin. For vertically distributed reservoirs, oil is often trapped within the lower interval, and gas is trapped at the upper interval. For a basin dominated by a vertical migration regime, the potential risk for hydrocarbon lateral travel far away from the kitchen is high, thus increasing the potential risk of prospectivity away from the kitchen. Understanding factors that help control vertical migration also help geologists better understand hydrocarbon distributions within the basins.
Case studies during which modeling helped determine the factors that influenced vertical hydrocarbon migration and the resulting potential phase distribution prospectivity risks in the studied basins are discussed.
The shale sector is studying the results of a 23-well experiment in the southeastern corner of New Mexico to learn what the wider implications might be. Researchers from the Federal Reserve Bank of Dallas quantified the economic impact of the US shale revolution for the first half of this decade. The green light for Santos Energy’s drilling program in the McArthur Basin comes after a moratorium on hydraulic fracturing in the Northern Territory was lifted in 2018. Findings from Kayrros suggest the average Permian well is both less productive and more expensive than reflected in public data. Permian Basin operators and service companies met to discuss completions diagnostics, flowback strategies, water management, and artificial lift strategies.
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.
This section features industry or work-related photographs submitted by readers. Selected pictures will be published on the website. Be sure to provide your full name, job position, company name, picture location, and a caption for the picture. Recently, I had the opportunity to go onboard the FPSO Armada Claire. Another beautiful sunrise onboard SIEM Helix 2 NS-52, where i-Tech 7 has two remotely operated vehic...
Africa (Sub-Sahara) Bowleven's Moambe exploration well on the Bomono Permit onshore Cameroon has encountered hydrocarbons. The well was drilled to a planned total depth of 5,803 ft and made its discovery in Paleocene-aged (Tertiary) target reservoir intervals. Moambe is the second in a two-well exploration program on the permit. The first well, Zingana, also discovered hydrocarbons. The Moambe well will be tested before further testing takes place at Zingana. Bowleven holds 100% interest in the permit. Shell Nigeria Exploration and Production has begun production at the Bonga Phase 3 project, an expansion of the deepwater Bonga project in Nigeria. Peak production from the expansion is expected to be 50,000 BOEPD, which will be shipped by pipelines to the Bonga floating production, storage, and offloading facility.
This paper attempts to use analogs of coals and Coal bed Methane (CBM) properties in Sedimentary basins to mutual advantage from the knowledge of each other.
An attempt has been made here to showcase as to why two Coal bearing formations, Lower Eocene, Cambay in India and Miocene, South Sumatra, Indonesia can be compared with each other in terms of coal quality and CBM characteristics.
Cambay basin, with an area of 56,000 sq kms is an elongated NNW-SSE rift basin in the western part of India. The basin fill comprises Mesozoic(?) sediments capped by Late Cretaceous Deccan volcanics and a thick tertiary pile of fluvio deltaics. Thick Lignite to sub bituminous coal is found in Middle (two thick seams) and Lower Eocene section (three thick seams of 20-35 m range and one thin seam of 1-10m). Chemically, the Middle Eocene lignite-sub bituminous coal is characteristically low in moisture (4-5%), quite low in ash (1-11%) and high in volatiles (43-55%). The Lower Eocene coals are sub bituminous with 10-20% moisture, low ash(5-10%), low Sulphur(<1%) content. The gas content of the Lower Eocene coals are 6 cubic metre / tonnne, with permeability 1-3 Md with seams slightly over pressured. Depth ranges of both these coal horizons are between1000-1800m approximately.
South Sumatra basin, double in size wrt Cambay basin with an area of 100,000 sq kms, is a NE-SW trending, backarc basin. Series of half grabens punctuated with basement highs, holds Miocene and Eocene Coals in the grabens of a mostly Tertiary sedimentary pile. The Miocene coals (formed in tide dominated coastal plain) are sub bituminous, with VRo 0.4-0.5, low ash(<10%), Moisture(10-18%), high volatile matter of around 40% at depths 300-1000m, with 20-30 seams with gas content of 7 cubic metre / tonne. The Older Eocene Coals are1-10 m thick at depths 1000-2000m formed in peat bogs in fluvial settings.
The Indonesian Coals of Miocene age are very comparable in coal properties and gas content to the Middle and Lower Eocene Coals of Cambay basin and can supplement each other in studies for CBM exploration and exploitation. Of great similarity are the coal quality, ash% and gas content. To take the comparisons further ahead, detailing of thickness, extent, geometry and depositional environments of each of these basins would be advantageous.
Mulyani, Sri (Schlumberger) | Sarmiento, Zammy (KS Orka) | Chandra, Vicky (Sorik Marapi Geothermal Power) | Hendry, Ridha (Sorik Marapi Geothermal Power) | Nasution, Syukri (Sorik Marapi Geothermal Power) | Hidayat, Ryan (Sorik Marapi Geothermal Power) | Jhonny, Jhonny (Schlumberger) | Sari, Pebrina (Schlumberger) | Juandi, Dedi (Schlumberger)
Understanding the reservoir conditions through 3D subsurface modeling is the key to optimize the exploration stage in geothermal field. A calibrated reservoir model based on updated data can be very important for this process. The main challenge of reservoir characterization in a geothermal field is the lack of subsurface data, therefore surface data are useful for reservoir modeling. This study utilized Sorik Marapi geothermal field data as a reference for reservoir modeling. This field is one of the geothermal fields in Indonesia that has been recently drilled, with results indicating the existence of a high temperature-neutral acidity resource. Initial reservoir model has been built from the previous study to create conceptual 3D subsurface model which includes structural, lithology, resistivity, and temperature distribution from surface exploration data, including surface mapping, remote sensing image interpretation, the magnetotelluric method, and subsurface data from six wells data.
The objective of this paper is to calibrate the initial reservoir model with information from an additional ten new wells data to improve delineation for updated reservoir area in the field. Software that allowed multidisciplinary data integration from surface to subsurface information was used for the calibration of the initial 3D model. The workflow to calibrate the model started with data loading and quality control, preparing the old 3D model and comparing it to new well data, analyzing the comparison, and updating the 3D model. Finally, the new delineation of reservoir zone can be determined.
The result of this study is an updated 3D subsurface static model defining the vertical and lateral reservoir boundaries, as well as the prime resource areas, which would be the basis for designing future well targets, and parameters for a dynamic reservoir model. The same model can be expanded to construct the numerical model to match the natural state condition of the field and make forecasts of the future reservoir behavior at different operating conditions. The main properties of the updated 3D model are lithology and temperature, which are important in geothermal reservoir delineation.
Chen, Peng (CNPC Engineering Technology R&D Co. Ltd.) | Zhou, Yingcao (CNPC Engineering Technology R&D Co. Ltd.) | Wang, Junjie (CNPC Chuanqing Drilling Engineering Co., Ltd.) | Chen, Lei (CNPC Engineering Technology R&D Co. Ltd.) | Li, Wanjun (CNPC Engineering Technology R&D Co. Ltd.) | Yang, Guobin (CNPC Engineering Technology R&D Co. Ltd.)
Tight and extra-low permeability reservoir was usually explored by use of normal underbalanced drilling if the wellbore is stable and the formation pressure is clear. However, precise underbalanced MPD is the optimal technical solution in case the borehole is unstable and the formation pressure is unclear. Moreover, the precise underbalanced MPD would be effective for reservoir protection, enhancement of hydrocarbon discovery, improvement of ROP as well as reduction of well control risk.
No oil and gas show were found by previous conventional drilling in a tight granitic basement of Indonesia. The first exploratory well was planned to explore the broken belt of the basement to discover the oil and gas zone, increase drilling efficiency, prevent lost circulation at crushed zone of the basement and minimize drilling troubles by utilization of precise underbalanced MPD in the potential target zone. Underbalanced MPD was achieved by use of low density water-in-oil drilling fluid, and the bottomhole underbalanced pressure fluctuation was accurately and effectively controlled.
Underbalanced MPD operation was smoothly completed. Drilling with ignition under balanced managed pressure, connecting triples under balanced managed pressure, and tripping under balanced managed pressure were implemented. Slight under balanced condition of the bottomhole pressure during MPD operation was realized. The backpressure of the wellhead was accurately controlled between 55-135psi during precise MPD operation. 57 times of total accumulate successful ignition lasted 240 hours, which accounts for 80% of the total drilling time. The rate of penetration in tight target granitic formation under balanced drilling was improved and reached 10.8ft/hr. Neither losses nor overflow were detected during underbalanced MPD. Safe and high efficient drilling was realized. Good oil and gas show were observed. Abundant natural gas produced during underbalanced MPD. The basement hydrocarbon reservoir has been obtained important discovery.
Application of precise MPD technology could accomplish reservoir discovery and protection, wellbore stability and reduction of well control risk. It prevents ordinary underbalanced drilling from change over traditional overbalanced drilling due to unable to satisfy the safe drilling which would result in secondary damage to the reservoir so as to improve integrated drilling efficiency.
CEPSA Colombia developed an improved technique for bioremediation; implemented since 2012 in the onshore Caracara field. This optimizes the processes of biostimulation and bioaugmentation by introducing exogenous bacteria, with efficiency (reduction of grease and oil) close to 90%.
The technique exceeds the performance of other published methods, as it has been used successfully for the biotreatment of soils and fluids impregnated with hydrocarbons at concentrations of fats and oil of up to 20 ± 2 wt%, equivalent to 200,000 ± 20,000 ppm (mg carbon/kg soil). Previous studies have suggested that oily sludges only with concentrations of fats and oils below approximately half that level can be bioremediated to achieve a compliance criterion standard close to 1 wt% as established in Chapter III of Louisiana Protocol 29-B and commonly adopted as an oil industry norm.
It is an ‘ex situ’ process since although applied at the field location the sludge is first collected and stored prior to batch biotreatment. The technique is most applicable to oily sludges that do not have an excessive asphaltene and resins content: asphaltenes are not biodegradable by microorganisms, given their structural complexity and resistance to the enzymatic attack produced by bacteria.
Our successful field pilot has been expanded to an industrial scale and has over a six-year period effectively treated the environmental liability of sludge ponds of approximately 12,000 m3 inherited when CEPSA assumed its interest in the Caracara field. Operations continue, treating ongoing generation of oily waste at an estimated cost saving of 54% relative to the treatment and transport costs of contracting an external bioremediation service provider.
We have developed simple criteria to screen the suitability of oily sludges for our process, which is simple, easy to implement and cost-effective, as it relies on bacteria generated from waste products readily available in the field at no cost. It should be applicable to other fields with similar environmental conditions.