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Pattani
Abstract Lost circulation is the most common drilling issue for infill drilling projects in Satun-Funan Fields, South Pattani Basin, Gulf of Thailand (GOT). The depleted sand is possible to be a root cause in many wells based on observation from resistivity time-lapse separation in depleted sands or shale nearby. Therefore, the objective of this study is to estimate fracture pressure related to the depleted sand and design an appropriate Equivalent Circulating Density (ECD) threshold for each well to avoid or minimize lost circulation and well control complication during drilling a new well. This study model is using Eaton (1969) equation. There are 3 input parameters which are Poisson's Ratio and pre-drilled estimated depletion pressure and depth. With limitations of no actual fracturing data and limited sonic log, the maximum ECD while lost circulation reading from Pressure While Drilling (PWD) tool and formation pressure test data were used to back-calculate for Poisson's Ratio and identified a relationship with depth. From the total of 68 wells in the Satun and Funan areas, the interpreted Poisson's Ratio ranges from 0.36 to 0.44 and its linear trend is apparently increasing with depth. To minimize the variation of back calculated Poisson's Ratio the local data become an important key for model validation and maintain the similarity of subsurface factors. This interpreted Poisson's ratio trend will be used to calculate for fracture pressure by incorporating with estimated depletion pressure and depth that expect to encounter in each planned well. The lowest fracture pressure in a planned well is used to prepare pre-drilled ECD management plan and a real-time well monitoring plan. Additionally, the model can be adjusted during the operational phase based on the new drilled well result. This alternative model was applied in 4 trial drilling projects in 2019 and fully implement in 6 drilling projects in 2020. The lost circulation can be prevented with value creation from expected gain reserves section is $57M and cost avoidance from non-productive time due to lost circulation is $3.4M. With an effort, good communication and great collaboration among cross-functional teams, the model success rate increases by 12%. However, there are some unexpected lost events occurred even though the maximum ECD lower than expected fracture pressure. This suspect as a combination of limitations and uncertainties on key input parameters and drilling parameters. In the future, the model is planned to expand to other gas fields in the Pattani Basin which will move to more infill phase and have higher chance of getting lost circulation to maximize benefits as the success case in Satun and Funan fields.
- Geology > Geological Subdiscipline > Geomechanics (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.34)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pailin Field (0.99)
- Asia > Thailand > Gulf of Thailand > Erawan Field (0.99)
- (5 more...)
Pore Pressure Estimation by Using Machine Learning Model
Booncharoen, Pichita (Chevron Thailand Exploration and Production) | Rinsiri, Thananya (Chevron Thailand Exploration and Production) | Paiboon, Pakawat (Chevron Thailand Exploration and Production) | Karnbanjob, Supaporn (Chevron Thailand Exploration and Production) | Ackagosol, Sonchawan (Chevron Thailand Exploration and Production) | Chaiwan, Prateep (Chevron Thailand Exploration and Production) | Sapsomboon, Ouraiwan (Chevron Thailand Exploration and Production)
Abstract In the past few years, over hundreds of wells were drilled in Gulf of Thailand, had faced with the depletion and lost circulation issues resulted from a lack of pressure data. A prior research of reservoir depletion pressure (Fangming, 2009) in oil field, China was obtained from multivariate statistic and regression by using density and neutron porosity log curves in logging-while-drilling data. However, the relative errors are 7.5% from the actual formation pressure. Thus, there are several latent variables in the model like drilling parameters (Rehm, 1971) which part of formation pressure. From 2018 initiative model in Satun-Funan, the classification model was obtained by using mud gas, porosity, water saturation, net sand thickness, net-hydrocarbon-pore thickness and neutron-density separation. However, the limitation is drilling parameters could not account by classifier, and accurate only original pressure category. So, this study has expanded scope to include other reservoir properties and drilling parameters then applied with machine learning on offset well dataset by using three regressors such quantile, ridge and XGBoost regressors. The pore pressure estimation model aims to improve efficiency for making decision in execution phase, increasing confidence in perforation strategy. The model parameters, pay thickness, porosity, water saturation, original pressure from local pressure profile and total gas show are accounted into this model. As of regressor assumption, some facts are conducted to logarithm and perform 2nd polynomial feature for model flexibility. There are three steps for building model such as data manipulation, analysis and deployment. Two purposes of pressure prediction impact algorithm selection, for operational phase, quantile regressor is implemented to provide conservative prediction while Ridge or XGBoost regressors are alternatives for perforation strategy, provide mid case result of pressure prediction. Overall model performance was measured using root mean square error (RMSE) on train & test dataset which show approximately 1.2 and 1.5 ppg range of accuracy respectively from total 12 drilling projects in Pattani basin. Overall model fitting is within reasonable range of generalization capacity to apply with unknown data point (test set). The future model will continue to improve accuracy and manage imbalanced dataset between original pressure and depleted sands.
- Asia > Thailand > Gulf of Thailand (0.37)
- North America > United States > Louisiana (0.34)
- Asia > Vietnam > Gulf of Thailand (0.26)
- (5 more...)
- North America > United States > Louisiana > China Field (0.99)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin (0.99)
- (4 more...)
Abstract The objective of this study was to improve the accuracy of condensate gas ratio (CGR) prediction in the Pailin and Moragot areas. Conventional method to predict liquid component reserves used only long-life condensate gas ratio (long-life CGR) from near-by production platform(s). The long-life CGR data are available in the mature production platforms which commonly takes 1-2 years to observe the decline trend so that there is no available data in the new drilled area and non-production area. This might cause inaccurate prediction of liquid reserves in the future platform especially in the platform locates far away from the mature production area. Multiple data which are basin modeling, geochemical data, drill-stem test, and batch-level production were analyzed and integrated to improve the accuracy of CGR prediction and understand geological reasons of high or low liquid production platform. These data can improve the confident level for CGR estimation in the non-production area and help identify potentially high liquid production platforms. The results show that the high liquid production in Pailin and Moragot fields related with the differentiation of source rock and migration process. There are three (3) separated trends in Pailin field and two (2) trends in Moragot field using geochemical data and basin modeling data. The local DST data has been integrated to confirm the extent of potentially high liquid production in several future platforms which locates in non-production area. Also, the updated production data has been re-visited to estimate the new CGR for the project located near-by production platform.
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.94)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Myanmar > Gulf of Thailand > Pattani Basin (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Drillstem/well testing (1.00)
- Production and Well Operations > Well & Reservoir Surveillance and Monitoring (1.00)
How to Obtain Quality PVT Samples for Heavy Oils in the South East Asia Region
Platt, Chris J. (KrisEnergy) | Chevarunota, Natasha (KrisEnergy) | Taksaudom, Pongpak (KrisEnergy) | Daungkaew, Saifon (Schlumberger) | Duangprasert, Tanabordee (Schlumberger) | Khunaworawet, Tanawut (Schlumberger) | Lerdsuwankij, Thiti (Schlumberger) | Wattanapornmongkol, Sawit (Schlumberger) | Thongpracharn, Payap (Schlumberger)
Abstract Exploration activity is always associated with many challenges such as uncertain pore pressure, and uncertain formation depths and characteristics. Unconsolidated formation could cause more serious troubles for drilling, formation evaluation, and production such as borehole washout, wellbore collapse, and sanding if proper planning is not in place. In addition, a viscous oil can add another complication for fluid sampling operations. An unsuccessful logging program could have a major impact on the field development plan (FDP) and further field investment decision (FID). In the Gulf of Thailand (GoT), high temperature Pattani basin discovery wells, reservoir fluids are mainly gas and condensate. There are numbers of waxy oil reservoirs1–5 in certain area in the GoT, notably in the cooler peripheral Tertiary basins. However, the subject field is the first one that was identified as having productive heavy oil reservoirs. The viscosity variation ranges between 1 and 100 cp2–6. It was observed that there was a depth related variation with deeper reservoirs having higher viscosities, and therefore, reservoir fluid information is crucial for the FDP and FID resulting from a field extension drilling campaign in early 2018. This paper will discuss step by step (1) reservoir characterization challenges (2) proposed methods to obtain reservoir and fluid information, as well as the interval pressure transient test, (3) the actual field results, (4) recommendations and way forward for similar reservoirs. Different proposed options are also discussed with field examples to obtain high quality PVT samples. Pumping to clean up high viscous oil contaminated tends to attract finer particulates towards the probe and into the flowline, causing plugging issues in other probe types even though a modified sand filter was added. In the end, the 3D Radial probe was proven in making this exploration campaign a success story for acquiring the heaviest oil samples to date in the GoT. The 3D Radial probe equipped with mesh filter plays an important role to restrict ingress of small sand particles, thereby allowing both sustainable pumping speed and flowing pressure. The single packer design also helps to support the formation preventing drawdown collapse. Coupled with larger flow area of the probe itself, the 3D Radial Probe has ability to control flowing pressure to stay above the sand break-away pressure even as more viscous formation oil enters. However, job objectives were achieved, which were formation pressure acquisition, high-quality fluid sampling, and Interval Pressure Transient Testing (IPTT) as well as Vertical Interference Testing (VIT). This paper also discusses the comparison between Downhole Fluid Analysis results and PVT lab analyses. Limitation and challenges for downhole measurements for this heavy oil environment. Advantages and disadvantages for different testing methods for this heavy oil reservoir will also be discussed.
- Asia > Vietnam > Gulf of Thailand (0.24)
- Asia > Thailand > Pattani > Pattani (0.24)
- Asia > Thailand > Gulf of Thailand (0.24)
- (3 more...)
- South America > Venezuela > Anzoátegui > Eastern Venezuela Basin > Maturin Basin > Cerro Negro Area Field (0.99)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin (0.99)
- (3 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- (3 more...)
How to Obtain Quality PVT Samples for Heavy Oils
Platt, Chris (KrisEnergy) | Chevarunota, Natasha (KrisEnergy) | Taksaudom, Pongpak (KrisEnergy) | Daungkaew, Saifon (Schlumberger) | Duangprasert, Tanabordee (Schlumberger) | Khunaworawet, Tanawut (Schlumberger) | Thiti Lerdsuwankij, Thiti (Schlumberger) | Wattanapornmongkol, Sawit (Schlumberger) | Thongpracharn, Payap (Schlumberger)
Abstract Exploration activity is always associated with many challenges such as uncertain pore pressure, and uncertain formation depths and characteristics. Unconsolidated formation could cause more serious troubles for drilling, formation evaluation, and production such as borehole washout, wellbore collapse, and sanding if proper planning is not in place. In addition, a viscous oil can add another complication for fluid sampling operations. An unsuccessful logging program could have a major impact on the field development plan (FDP) and further field investment decision (FID). In the Gulf of Thailand (GoT), high temperature Pattani basin discovery wells, reservoir fluids are mainly gas and condensate. There are numbers of waxy oil reservoirs1–5 in certain area in the GoT, notably in the cooler peripheral Tertiary basins. However, the subject field is the first one that was identified as having productive heavy oil reservoirs. The viscosity variation ranges between 1 and 100 cp2–6. It was observed that there was a depth related variation with deeper reservoirs having higher viscosities, and therefore, reservoir fluid information is crucial for the FDP and FID resulting from a field extension drilling campaign in early 2018. This paper will discuss step by step (1) reservoir characterization challenges (2) proposed methods to obtain reservoir and fluid information, as well as the interval pressure transient test, (3) the actual field results, (4) recommendations and way forward for similar reservoirs. Different proposed options are also discussed with field examples to obtain high quality PVT samples. Pumping to clean up high viscous oil contaminated tends to attract finer particulates towards the probe and into the flowline, causing plugging issues in other probe types even though a modified sand filter was added. In the end, the 3D Radial probe was proven in making this exploration campaign a success story for acquiring the heaviest oil samples to date in the GoT. The 3D Radial probe equipped with mesh filter plays an important role to restrict ingress of small sand particles, thereby allowing both sustainable pumping speed and flowing pressure. The single packer design also helps to support the formation preventing drawdown collapse. Coupled with larger flow area of the probe itself, the 3D Radial Probe has ability to control flowing pressure to stay above the sand break-away pressure even as more viscous formation oil enters. However, job objectives were achieved, which were formation pressure acquisition, high-quality fluid sampling, and Interval Pressure Transient Testing (IPTT) as well as Vertical Interference Testing (VIT). This paper also discusses the comparison between Downhole Fluid Analysis results and PVT lab analyses. Limitation and challenges for downhole measurements for this heavy oil environment. Advantages and disadvantages for different testing methods for this heavy oil reservoir will also be discussed.
- Asia > Vietnam > Gulf of Thailand (0.24)
- Asia > Thailand > Pattani > Pattani (0.24)
- Asia > Thailand > Gulf of Thailand (0.24)
- (3 more...)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Myanmar > Gulf of Thailand > Pattani Basin (0.99)
- (2 more...)
- Reservoir Description and Dynamics > Unconventional and Complex Reservoirs > Oil sand, oil shale, bitumen (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Pressure transient analysis (1.00)
- (3 more...)
Abstract Detailed knowledge of fill-spill history and charge entry points to fields is rarely available, due to lack of suitable data sets and methodologies. This paper describes the application of a reservoir geochemical work flow (multi-variate statistical analysis of geochemical data) to unravel the fill history of a highly complex oil field in the northern Gulf of Thailand, and the implications of these results in assessing charge risk in adjacent and near-field prospects. The Jasmine-Ban Yen field, Pattani Trough, Gulf of Thailand, produces from stacked Middle to Late Miocene clastic reservoirs, draped over a highly faulted structural nose. In an earlier study, 59 oils from across the field underwent standardised fingerprinting, biomarker and bulk isotope analysis. Here, geochemical parameters considered resistant to secondary processes such as biodegradation, underwent hierarchical cluster analysis and classification into fluid families. Distinct families potentially represent fluids that share a common history. The results were synthesised with spatial information, seismic data, reservoir pressures, petroleum systems modelling, and observations drawn from the field's production history, to elucidate the fill-spill history of the field. All oils were expelled from similar lacustrine organofacies at similar maturity, which is broadly consistent with a single source pod charging the field. The closest mature kitchen is thought to be located in the Northern Pattani Trough, some 20 to 25 km to the south. A sub-regional Middle Miocene lacustrine seal, the "hot shale," focusses oil into the Jasmine-Ban Yen field, and forms the seal for 30% of the STOIIP. Fluids also occur in reservoirs above this seal, which could be emplaced either through vertical fill and spill via high offset faults, possibly aided by locally high CO2 increasing buoyancy pressure by formation of a gas cap, or laterally, via spill from adjacent fault blocks. Detailed knowledge of charge history remains elusive; however, the occurrence of consistently different fluid families above and below the hot shale seal, with fluids below represented by consistent families over a lateral distance of 12 km, supports an interpretation of multiple entry points into the field. Aromatic maturity parameters indicate that four Ban Yen samples are of slightly elevated maturity, suggesting that late charge accesses the field above the hot shale. The possibility that the differences between families are related to biodegradation was investigated and discarded. Families probably represent discrete, lateral spill pathways reflecting multiple charge entry points and are differentiated by subtle variations in organofacies related to oxicity and contribution from plant material. Comparable migration above and below the hot shale into B5/27 is a possibility, and exploration prospectivity is risked accordingly. Placing statistically derived fluid families into a spatial, geological and production context enables unravelling of migration vectors in complex fields. Furthermore, inferences may be drawn from such a study that can help guide risk assignment to offset exploration prospectivity.
- Asia > Thailand > Gulf of Thailand (0.70)
- Asia > Vietnam > Gulf of Thailand (0.55)
- Asia > Myanmar > Gulf of Thailand (0.55)
- (3 more...)
- Geology > Geological Subdiscipline > Geochemistry (1.00)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.89)
- Geology > Geological Subdiscipline > Economic Geology > Petroleum Geology (0.87)
- Geology > Sedimentary Geology > Depositional Environment > Continental Environment > Lacustrine Environment (0.56)
- Oceania > Australia > Western Australia > North West Shelf > Carnarvon Basin > Dampier Basin > WA-20-L > Legendre Field > Angel Formation (0.99)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Myanmar > Gulf of Thailand > Pattani Basin (0.99)
- (3 more...)
Abstract Horizontal well technology has been used in the Pattani Basin to target oil and gas reservoirs since the late 1990’s. As of today, the Chevron Operated B8/32 block and Platong fields have been producing from 70 horizontal wells. While about 80 % of the horizontal wells in Platong have been completed barefoot, the use of ICD’s has been increasing since 2010. Recently, in the Platong field, two ICD equipped horizontal wells were used initially for primary production of a major reservoir, following which one of the two wells was converted into a water injector to enhance total recovery from the reservoir. The ‘Z’ reservoir located in Platong field has significant barrels (in the millions) of oil in place with an initial gas cap and a water leg. The reservoir was initially appraised and tested with a single deviated wellbore. This well confirmed the reservoir potential and identified gas and water coning, together with sand production as the major risks to optimising oil recovery. To manage potential oil and gas coning, a reservoir development plan, based around a pair of horizontal well completions, was developed. Both well completions were designed with sand control screens incorporating ICD’s to optimize inflow along each horizontal wellbore. The wells were drilled and completed in early 2012. After collecting surveillance data and modeling the primary production performance of the reservoir, a waterflood opportunity to increase total recovery was planned. The asset team implemented the in-situ conversion of one of the horizontal wells into a waterflood injector in August 2013. Response to the water injection has been confirmed in the second well of the pair and incremental oil of >50 MBO has been recovered. This case study presents an analysis of the target reservoir, the development strategy and then captures the lessons learned from the performance of horizontal producers with ICD completions during primary production and during the later waterflood phase. The main challenges for future horizontal wells applications in Platong are relatde to thin fluvial sands and depletion. The use of ICD’s will continue to be proposed for new horizontal targets based on the positive incremental production impact.
- Energy > Oil & Gas > Upstream (1.00)
- Water & Waste Management > Water Management > Lifecycle > Disposal/Injection (0.36)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Myanmar > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Malaysia > Gulf of Thailand > Pattani Basin (0.99)
- (2 more...)
Abstract It has been recognized from the early stages of exploration in the 1980s that gas bearing reservoirs with condensates were located at depths of approximately 4,000 to 5,000 feet in parts of the Pattani Trough, Gulf of Thailand. However, even though the entire pay window is evaluated for each prospect area, no regional study on the shallow hydrocarbons has been made due to the majority of hydrocarbons residing in deeper zones. In the Gulf of Thailand there are two major Cenozoic sedimentary basins, the Pattani Trough and the Malay Basin. In the Pattani Trough, commercial production started at the Erawan gas field in 1981 and subsequently more than 20 oil and gas fields have been discovered and have continued producing hydrocarbons at the current date. The Pattani Trough is a rift type-sedimentary basin and the maximum thickness of sediments is more than 10 km. The geological column is divided into five sedimentary units from Sequence 1 to 5 in ascending order. Two major unconformities are identified: one is called the Middle Cenozoic Unconformity (MCU) and the Middle Miocene Unconformity (MMU). The latter unconformity is located between Sequence 4 and Sequence 5. Oil and gas are mainly trapped in fluvial to deltaic sandstones of Sequence 3 and Sequence 4 located between 5,000 to 9,000 feet. Structure is characterized by many normal faults. Based on the more than 800 wells and 3D seismic data, detailed studies on well correlation, dip-meter, micropaleontology, regional isopachs and sand-shale ratio were made and it was concluded that the these shallow hydrocarbons are closely related to the incised valley-fill sediments located in the lower part of Sequence 5 immediately above the MMU. Hydrocarbons generated in the deeper levels have migrated upward through faults and moved into and are possibly trapped in the incised shallow reservoirs. Previous wells were drilled in the highly faulted areas where most of the oil and gas is trapped and there are no wells drilled in the monocline areas. Although the detailed areal distribution of the incised valleys is not clearly identified, hydrocarbons are expected in monocline areas if conditions are favorable. Since the MMU is widely developed in the South East Asia, this type of exploration concept focusing shallow hydrocarbons can be applied not only for the undrilled area of the Pattani Trough but also for the mature sedimentary basins such as the Malay and Nam Con Son basins.
- Asia > Vietnam > Gulf of Thailand (1.00)
- Asia > Thailand > Pattani > Pattani (1.00)
- Asia > Thailand > Gulf of Thailand (1.00)
- (3 more...)
- Phanerozoic > Cenozoic > Paleogene (1.00)
- Phanerozoic > Cenozoic > Neogene > Miocene > Middle Miocene (0.35)
- North America > Canada > Saskatchewan > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- North America > Canada > Alberta > Western Canada Sedimentary Basin > Alberta Basin > Viking Formation (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin > Contract Area 2 > Satun Field (0.99)
- (10 more...)
Abstract E-log provides not only reservoir parameters to evaluate hydrocarbon reserves but also geological information on erosion thickness in addition to sedimentary environments (Pirson, 1970 and Zimmerle, 1995). Erosion thickness is one of the key issues for hydrocarbon generation, expulsion, migration and trapping in oil and gas exploration. Although there are several methods to estimate erosion thickness, two kinds of methods were applied in this study for reasons of practicality and accuracy, namely;conventional reconstructed section method; and Magara method (1978) with use of sonic logs. Magara method is the only method which uses sonic logs to estimate erosion thickness based on shale compaction trend. Shale compaction method was applied to the Pattani Trough of the Cenozoic basin in the Gulf of Thailand for 122 wells in 13 oil and gas fields. However, the method gave extraordinarily large values for erosion thickness of the Middle Miocene Unconformity (MMU) compared to the results of conventional reconstructed method because of the high velocity of Sequence 4 located immediately below the MMU. The main reasons for the high velocity of Sequence 4 are considered to be:hardening by hydrothermal water; high concentration of certain rocks or minerals such as calcite, iron, pyrites etc.; and alternation of clay mineral by heat through "chemical compaction" (Pollastro, 1993 and Bjorlykke, 1999). It is evident that a hydrothermal event occurred locally in the Pattani Trough (Sasaki, 1986 and Fujiwara & Sasaki, 1988). Mud logs obtained at 7 wells and the temperature gradient derived from bottom hole temperature (BHT) at more than 70 wells were reviewed. There appears to be no strong relationship between lithology and the high velocity of Sequence 4 and temperature gradient is high [2.74°F / 100 feet (4.99°C / 100 m)] on average which is almost identical to the island of Sumatra in Indonesia. Therefore, alternation of clay mineral from smectite to illite conversion under high temperature conditions is one of the main factors that explain the high velocity of Sequence 4. In case of application of the Magara method in hot basins such as those in South East Asia, careful attention should be paid. Conventional reconstructed section method is also recommended together with the Magara method.
- Geology > Mineral > Silicate > Phyllosilicate (1.00)
- Geology > Mineral > Sulfide > Iron Sulfide > Pyrite (0.55)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.50)
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Phitsanulok Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin > Contract Area 2 > Platong Field (0.99)
- (6 more...)
Abstract The Platong field is a mature field situated in the northern section of the Pattani basin which is composed of both oil and gas reservoirs. A major characteristic of this field are small faulted, compartmentalized fluvial reservoirs with depletion drive as the main drive mechanism. With small reservoirs and an absence of aquifer support, recovery from primary oil production is low. Commingling production from multiple reservoirs is required to improve production rate and develop each reservoir at a lower cost. Aggressive infill programs are required to offset sharp production decline unless secondary recovery methods can be utilized to boost production. In 2011, the field marked another major accomplishment in reservoir management (RM.) During the year, the base layer oil decline rate was flattened from the preceding 5 year range of 27% to 42% average annual decline rate per year to less than 15%, Figure 1. This significant improvement in the production performance resulted from proactively implementing strong RM fundamentals through cross-functional teams and delivering on waterflood and gas lift projects.
- Asia > Vietnam > Gulf of Thailand > Pattani Basin (0.99)
- Asia > Thailand > Gulf of Thailand > Pattani Basin > Contract Area 2 > Platong Field (0.99)
- Asia > Myanmar > Gulf of Thailand > Pattani Basin (0.99)
- (3 more...)