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.
Bai, Chunlu (School of Mechanical Engineering, Beijing Institute of Petrochemical Technology) | Liu, Meili (School of Mechanical Engineering, Beijing Institute of Petrochemical Technology) | Chen, Jiaqing (Beijing Key Laboratory of Pipeline Critical Technology and Equipment for Deepwater Oil & Gas Development, Beijing 102617, China) | Wang, Chunsheng (School of Mechanical Engineering, Beijing Institute of Petrochemical Technology) | Shang, Chao (Beijing Key Laboratory of Pipeline Critical Technology and Equipment for Deepwater Oil & Gas Development, Beijing 102617, China) | Zhang, Ming (Beijing Research Center, CNOOC China Co. Ltd)
Efficient and compact separation technology is in urgent need for many oilfield exploitations because of increasing water cut and strict discharge regulations. A compact axial hydrocyclone is presented to pre-separate water from the wellstream. Experimental investigation was carried out to qualify its performance. A test loop is designed to perform experimental investigations. The flow loop is fabricated to manipulate and control various operational variables, such as the oil/water mixture flow rate (0.5-2 m3/h), the oil droplet size, and the water-to-oil ratio (65/35 to 100/0). A combination of venturi tube and static mixer is used to mix oil/water mixture. Dehydration rate and oil concentration at water outlet are used to evaluate the oil/water separation performance. A series of experiments have been carried out to test the performance of the novel hydrocyclone. Inlet parameters, including inlet flow rate, water cut, droplet size and split ratio, have been evaluated. Inlet flow rate, water cut, and droplet size have significant effects on the separation performance. When the oil concentration in the water outlet is controlled to be less than 1,000 ppm, a maximum dehydration rate of 70% can be obtained. The compact axial hydrocyclone exhibits high separation performance and reliability for a wide range of operating conditions. A stable oil core without vortex oscillations is observed. This effect, combined with the low pressure drop, indicates a stable swirl with low turbulence, which enables a higher capacity of the compact axial hydrocyclone compared to traditional hydrocyclone.
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.
Africa (Sub-Sahara) Eni has begun production from the Vandumbu field and made a new oil discovery in the Afoxé exploration prospect in Block 15/06 offshore Angola. First oil from the Vandumbu field, through the N'Goma floating production, storage, and offloading vessel, was achieved in late November, 3 months ahead of schedule. Vandumbu is approximately 350 km northwest of Luanda and 130 km west of Soyo. This, along with the startup of a subsea multiphase boosting system in early December, boosts oil production from Block 15/06 by 20,000 B/D. The rampup of Vandumbu is expected to be completed in 1Q 2019. Block 15/06 is being developed by a joint venture formed by Eni (36.84%, operator), Sonangol (36.84%), and SSI Fifteen (26.32%). Asia Pacific Ophir Energy's Paus Biru-1 exploration well in the Sampang production-sharing contract (PSC) offshore Indonesia has resulted in a gas discovery.
Merza Media, Adeyosfi (Schlumberger) | Muhajir, Muhajir (Pertamina Hulu Energi Tuban East Java) | M. Wahdanadi, Haidar (Joint Operating Body Pertamina Petrochina East Java) | Agus Heru, Purwanto (Joint Operating Body Pertamina Petrochina East Java) | Anugrah, Pradana (Schlumberger) | Dedi, Juandi (Schlumberger)
Most of sedimentary basins in Indonesia contain productive carbonate reservoirs. Geologically, the reservoirs are mostly part of a reef complex and carbonate platform, with basinal areas situated mainly in the back arc of the archipelago. Many of the productive carbonate reservoirs have dual porosity systems with widely varying proportions of primary and secondary porosity. Carbonates of the Tuban formation in Platinum field represent two carbonate buildups identified with similar effective porosity but different productivity. This paper describes a method for characterizing secondary porosity distribution at the wellbore and field scales to address the productivity difference between the northern and southern carbonate buildups in this field.
To resolve the challenges in characterizing secondary porosity in a carbonate formation, an integrated workflow was developed that consists of combination of quantitative and textural analysis based on borehole images at the single-wellbore scale and the seismic inversion result to control lateral distribution at the field scale. Analysis based on borehole image log provides high-resolution porosity characterization based on its size, interconnectivity, and type. The result of the single-wellbore analysis will be distributed at the field scale with control of a seismic attribute such as acoustic impedance (AI). Acoustic impedance is built with stochastic seismic inversion to provide a higher-resolution result compared to the deterministic seismic inversion method.
The result of the analysis based on borehole images at the single-wellbore scale shows most of the northern carbonate buildup wells demonstrate high development of porosity from interconnected vugs, leading to a relatively high permeability interval. In contrast, the southern carbonate buildup wells demonstrated low secondary porosity development. Low secondary porosity development is related to cemented zones and the predominance of claystone facies in a well. Later, the result of the single-wellbore scale analysis was distributed at the field scale with seismic attribute control such as AI. The Platinum field shows a negative correlation between AI and porosity with a value of -0.769; hence, the acoustic impedance from stochastic seismic inversion can be used to control the porosity distribution. The secondary porosity model shows a distinct difference between the northern and the southern carbonate buildups. The northern carbonate buildup has higher average secondary porosity compared to the southern carbonate buildup. The result was confirmed with production data; the northern carbonate buildup has higher productivity compared to the southern carbonate buildup.
This integrated workflow provides a comprehensive and high-resolution analysis of secondary porosity distribution at the single-wellbore scale and the field scale. Thus, this workflow can reduce uncertainty during reservoir characterization, well placement, and production planning.
Anis, Apollinaris Stefanus Leo (Schlumberger) | Syarif, Zilman (Saka Indonesia Pangkah Limited) | Setiawan, Ade Surya (Schlumberger) | Hidayat, Azalea (Saka Indonesia Pangkah Limited) | Murtani, Anom Seto (Saka Indonesia Pangkah Limited)
Ujung Pangkah Field which located at offshore East Java Indonesia, is known for its challenging nature from geological, reservoir and drilling perspectives. Drilling experiences in this area shows severe wellbore instability in overburden shale and in fractured carbonate reservoir. Hydrocarbon production directly exacerbate drilling problems and production issues that were not expected came earlier than predicted, for example early water breakthrough. At least two or three operators facing similar severe wellbore instability problems in the area.
Due to the complexity of subsurface systems and coupled interactions between depletion and stresses, the present-day stress state in Ujung Pangkah Field which have undergone production will be different from the pre-production stress state. Therefore, a comprehensive analysis will require numerical modelling involving coupling of 3D geomechanical model with fluid flow during production operations from dynamic model. Present-day stress state is subsequently used for wellbore stability analysis of planned development wells in Ujung Pangkah Field. Investigation of the behavior of natural fractured reservoir during depletion and its impact to reservoir management is also attempted. Two-way coupling of geomechanic and dynamic models were conducted whereby porosity and permeability update due to production were simulated based on uniaxial pore volume compressibility tests. Hence, porosity and permeability of fractures are not considered static anymore but dynamic due to stresses changes and production.
The result of coupled simulation is able to reduce wellbore instabilities significantly in the planned well. The stable mud weight windows for planned wells are extracted from the model. The stable mud weight window in the reservoir interval is narrow to no stable drilling window in all the planned wells due to depletion. In general, the preferred direction to drill, requiring lowest mud weights, is in the direction of minimum horizontal stress which in this case is Northwest-Southeast (NW-SE). However, it was found that azimuthal dependency of mud weight is insignificant due to low horizontal stress anisotropy.
Reservoir compaction and sea-bed subsidence were also calculated using the outputs from the model. The result is useful for completion and platform integrity.
Purnomo, Agung (Kangean Energy Indonesia) | Octaviani, Tenny (Schlumberger) | Paterson, Graeme (Schlumberger) | Pasaribu, Ihsan Taufik (Schlumberger) | Mori, Ryota (MCX Asia) | Ahmed, Aqil (Schlumberger) | Akama, Kenichi (Japex) | Aini, Muhamad Faizol Badrul (Schlumberger)
One of the key for successful drilling through carbonates build up structure is accurate time depth information to avoid kick-loss scenario during drilling if the carbonate is accidentally penetrated in the unexpected shallower hole size. Setting the casing point accurately to isolate the high overpressure regime on the overlying shale above the carbonate is required. During Kangean operation, Geostopping using Seismic While Drilling (SWD) technology was applied for setting the 9 5/8" casing before penetrating the Prupuh carbonate formation and updating the pore pressure model. This paper will demonstrate an application of SWD in Indonesia’s deepwater operation of predicting critical carbonate depth enabling well construction on time and on budget.
Acquisition of SWD was done during an acoustically ‘quiet’ period, during stand connections while pumps are off. Real-time waveforms are transmitted to surface through the mud telemetry system and sent to processing center via secure connection systematically after each seismic level acquired. Processing was done in real-time providing updated time-depth information, placing bit position on the seismic section in depth domain for refining depth prediction and ultimately Vertical Seismic Profile (VSP) corridor stack containing seismic reflectors along the wellbore and ahead of the bit for look-ahead information. The real-time updated interval velocity was used to update pore pressure model for monitoring the overpressured zone and to adjust mud weight accordingly while drilling to prevent a kick situation.
A total of 27 real-time SWD levels were acquired during drilling over interval ~1,800 ftMD. The data was found to be of a high quality that allowed for an accurate well tie of the Prupuh Carbonate top with a final depth prediction. Real time velocity showed that velocity of Cepu shale above the Prupuh carbonate was slower than pre-job velocity model, meaning that the Prupuh carbonate depth is shallower than initial prediction. Real time decision was made to set the casing before Prupuh Carbonate top. The actual Prupuh top was 23 ft deeper than the latest real time Prupuh prediction. This SWD technology allows us to reduce top carbonate uncertainty from +697 ft/-375 ft to become +/− 23 ft and ultimately saved the well from potential catastrophic event.
This study demonstrates that SWD technology give us confidence to manage risk in real-time.
Rahmanto, Wahyu Agung (Saka Indonesia Pangkah Ltd) | Setiawan, Andreas Lukman (Saka Indonesia Pangkah Ltd) | Triyono, Triyono (Saka Indonesia Pangkah Ltd) | Zulfikar, Zulfikar (Saka Indonesia Pangkah Ltd) | Handono, Indan (Saka Indonesia Pangkah Ltd) | Suryadana, Siswara (Saka Indonesia Pangkah Ltd) | Thopyen, William (Schlumberger) | Fah, Gordon Goh Kim (Schlumberger) | Wismawan, Satriya Galih (Schlumberger)
Pangkah field located at offshore East Java Indonesia is an oil and gas producer within fractured carbonate reservoir lithology. Fractured corridors introduce challenges during drilling and production phase. To optimize production, several wells had been completed with novel Inflow Control Device (ICD) design. This paper highlights the potentials of such customized ICD's innovation with integral sliding sleeve.
This novel ICD design preserves intended ICD position, and in addition could be shifted in the downhole later either to be in open or closed position if required. Either coil tubing or electric-line could be deployed to shift the downhole 3-positions of this integral ICD with sliding sleeve. The integral design allows a fully open position for well stimulation or circulation in formation damage treatment. Meanwhile another position enables ICD configuration for inflow control. The last position which is fully-shut or closed can be activated during completions string Run in Hole (RIH) to allow floating toward Total Depth (TD), minimizing torque and drag, and maintaining wash-down capability without wash pipe. The whole closed or floating system while RIH makes it possible to set assemblies of open hole hydraulic set packers or any pressure activated devices. During late-life, selective compartment could be shut-off against excessive water production decisively whenever required.
Good sealing of the open hole packers against borehole is essential for the effectiveness of open hole compartmentalization and ICD production. The open hole hydraulic packers must be placed and set properly within its expanding range. Combination of petrophysical analysis, caliper log, image log, seismic coherency, and drilling loss data are used to define the compartments and packer placement.
This novel ICD's innovation with water shut-off capability in addition to the main ICD's inflow control is designed comprehensively with 3D single wellbore dynamic modeling. ICD's single well dynamic modeling were executed along three phases i.e. pre-drilled, real-time and post-job. Each phase respond to operation readiness and reservoir management. Intensive engagement with asset team and realistic modeling design range lead to positive production results.