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.
Kamkong, Paphitchaya (PTTEP) | Karnjanamuntana, Thamaporn (PTTEP) | Prungkwanmuang, Weera (PTTEP) | Yingyuen, Jakkrich (PTTEP) | Oatwaree, Dejasarn (PTTEP) | Amornpiyapong, Nichakorn (PTTEP) | Khositchaisri, Patcharin (PTTEP) | Tivayanonda, Vartit (PTTEP) | Wongsuvapich, Dutkamon (PTTEP) | Tongsuk, Soraya (PTTEP)
Lunar field is a marginal gas field located in the Gulf of Thailand. A significant portion of reservoir sands is currently categorized as Additional Zones of Interest (AZI) which is not accounted in reserves. As for this kind of sand, the conventional petrophysical evaluation alone cannot certainly distinguish between hydrocarbon and water in the porous medium. The alternative method (dT LogR) for formation re-evaluation is therefore considered in attempt to reduce uncertainty in fluid classification and reveal hidden hydrocarbon potential from these AZIs.
There are 2 phases in verifying the validity of dT LogR method. Phase I: dT logR method (Ref.
Phase II: The production test data from perforated AZIs in phase I and the well correlation were then incorporated in dT LogR assisted log reinterpretation. Additional 13 gas-potential AZI candidates were identified for 2nd perforation test to prove the correctness of the recalibrated petrophysical model. The results showed success in model improvement of which its accuracy increased to 61% and no high water production was observed in any of them.
After using dT LogR method to assist petrophysical evaluation, a total of 469 metres of unperforated AZIs were reconsidered to be productive gas bearing formation. In other words, 22 BCF of gas reserves and 873 MSTB of condensate reserves from these upgraded AZIs were added. In addition, it is foreseen that the remaining AZIs of other platforms are to be further reevaluated and therefore improves the confidence in reserves booking and field development planning of Lunar Field.
In conclusion, the dT LogR method is a very useful tool for Lunar Field to significantly reduce uncertainty of fluid classification which in turn provides lots of benefits in gas field management adding immeasurable value to Lunar Field.
Koronful, Nour (Schlumberger) | Peters, Kenneth (Schlumberger) | Ali, Mohd Firdaus (Malaysia-Thailand Joint Authority) | Skulsangjuntr, Jirapha (Malaysia-Thailand Joint Authority) | Jiang, Long (Schlumberger) | Kleine, Adrian (Schlumberger) | Basu, Depnath (Schlumberger) | Bencomo, Jose (Schlumberger) | Hernandez, Jonathan (Schlumberger) | Brink, Gerhardus (Schlumberger)
High carbon dioxide in reservoirs limits successful exploration in many petroliferous basins, particularly in Southeast Asia. High reservoir CO2 in the offshore Malay Basin represents a significant exploration challenge. Some fields contain >80% CO2, which makes them unattractive targets for development. Various hypotheses on the origin of CO2 have been proposed but remain controversial. This paper shows that geochemistry and advanced petroleum system modeling help to resolve the origins of reservoir CO2 and allow quantitative estimates of CO2 in prospective reservoir targets prior to drilling. A novel workflow estimates the CO2 content in reservoirs based on knowledge of the chemical mechanisms for the origin of the CO2 and numerical simulation of geologic burial history. Heat flow, deposition of overburden rock, and the kinetics of specific reaction mechanisms control the timing of CO2 generation and the relative contributions of CO2 from different sources.
In this study, stable carbon isotope ratios of CO2 and methane (δ13CCO2 and δ13CCH4, ‰) were used to identify the source of the CO2 in Malay Basin gas samples. For example,
Setiawan, A. S. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Simatupang, M. H. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Rachmadi, A. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Ratanavanich, S. (Carigali-PTTEPI Operating Company Sdn. Bhd.) | Pushiri, M. F. Mohd (Carigali-PTTEPI Operating Company Sdn. Bhd.)
In the event of high gas demand, infill well drilling is one of the best option to increase gas deliverability. Finding infill well opportunity in a brown field is a challenging task. Reservoir continuity, heterogeneity of the rock properties, pressure depletion and identifying undrained area are the major concern for infill wells candidate selection. A robust reservoir characterization and dynamic information are essential to provide some key understanding about the field.
The area of interest, Muda field, is located in the Block B-17 of Malaysia-Thailand Joint Development Area (MTJDA) which has been producing for more than 5 years. Integration of multidisciplinary data is very important to identify the potential hydrocarbon bypassed area. To start with, the geological model was built and constrained with seismic attributes after calibration to the well data. The high uncertainty of reservoir presence in the model was assessed by combining the sand distribution and porosity variation. Subsequently, history matching was performed to calibrate the model with actual production flow rates and reservoir pressure. A reasonably good history match was achieved and provides a certain degree of confidence in production forecast. As a result, it shows some potential undrained areas to be selected as the area of infill well candidate. The infill wells were drilled within 1 to 2 years later and the well results has demonstrated a successful delivery of infill well as expected both in encountered netpay and production.
This paper discusses a successful collaboration between multidisciplinary team members in the subsurface division to deliver infill well candidate by building a comprehensive reservoir model which integrate of all hard data from geological concept, seismic attribute, well and production. Five successful infill wells were drilled in accordance to this campaign, expected potential and volume are generally as expected with some surprises in some interval. The gas potential comes from these infills are very important to fulfil gas deliverability. It is foreseen that additional infill wells are expected and evaluated using the 3D reservoir model.
Fadjarijanto, A. (Carigali-PTTEPI Operating Company) | Rachmadi, A. (Carigali-PTTEPI Operating Company) | Setiawan, A. S. (Carigali-PTTEPI Operating Company) | Praptono, A. (Halliburton) | Suriyo, K. (Carigali-PTTEPI Operating Company) | Simatupang, M. H. (Carigali-PTTEPI Operating Company) | Pakpahan, O. (Carigali-PTTEPI Operating Company) | Costam, Y. R. (Carigali-PTTEPI Operating Company) | Zakaria, Z. U. (Carigali-PTTEPI Operating Company)
Fluid identification is a key component of formation evaluation and becomes one of the important parameters that underlie economic decisions in field development. The combination of high clay content in the thinly laminated shaly-sand reservoir, together with unknown water salinity, increases the complexity in the accurate quantification of hydrocarbon-bearing reservoirs. The inherent clay distribution affects the log data response of high gamma and low resistivity analyses. Those responses can lead to incorrect interpretations unless other log data responses are considered.
The low resolution of a common oil-based resistivity tool often fails to capture structurally complex, thinly laminated sand-shale formations. The low resistivity response results from high resistivity sand layers suppressed by low resistivity shale layers, which can result in misinterpretations of calculating high water saturation. Observations of other conventional well log data can provide early qualitative identification of the low contrast zone. Data from the Thomas-Stieber method, resistivity anisotropy, and high-resolution micro-imaging are available to reconstruct conventional log data to provide an enhanced vertical resolution for final interpretations.
A field study was performed in the North Malay basin. Geologically, the field has three-way dip closure, bounded by a west-dipping fault to the west. The early evaluation of the DS2-B layer was interpreted as shale zones following a high gamma and low resistivity reading. Further observation of the density, neutron, and shear sonic trend do not provide the same shale indication. The decision was made to run a formation tester tool and to investigate any possible hydrocarbon indication. Real-time fluid identification and sampling proved the DS2-B layer to be gas-bearing and indicated that the conventional petrophysics-calculated water saturation was too high. Three petrophysics re-evaluation approaches were performed to define the reservoir challenges, including deterministic, Rv/Rh methods, and high-resolution data approach to obtain a better definition. All available data were used on the methodologies, based on the data required for each method, particularly the use of high-resolution imaging and core data for conventional logs to define the high-resolution of porosity, clay volume, and water saturation. As a result of these analyses, the DS2-B layer was proven to be a pay zone with a lower water saturation, which correlated with the formation sampling and core analysis results. The methodology has a proven capability to identify low contrast zones and can provide better interpretation in the field study through providing more a precise and accurate net-to-gross calculation.
The correlation and calibration of the conventional well log data to high vertical resolution image log, core data, and fluid sampling have provided a means of better visualizing and understanding the features of thinly bedded reservoirs in the field study. All methods were performed to calculate the final fluid saturation in highly laminated reservoirs. The new interpretation has proved a significant contribution to the NM field economic value.
Ali, M. F. (Malaysia-Thailand Joint Authority) | Hernandez, J. (Schlumberger) | Brink, G. (Schlumberger) | Koronful, N. (Schlumberger) | Xue, F. (Schlumberger) | Jiang, L. (Schlumberger) | Bencomo, J. (Schlumberger) | Ishak, A. Z. (PETRONAS) | Skulsangjuntr, J. (Malaysia-Thailand Joint Authority)
The study area of this paper is located in the mature North Malay Basin, within the offshore Malaysia-Thailand Joint Development Area (MTJDA). Exploration activities have been conducted since 1971 and several gas fields have been developed, mostly at relatively shallow stratigraphic levels of Late Miocene sequences. The study area covers 7250 km2, which includes exploration and production areas covered by approximately 300 wells, 6400 km2 of 3D surveys and 10664 km of 2D seismic line. The multi-disciplinary team was tasked to establish the overall hydrocarbon potential of the area, including potential new play-openers and covering the area outside of existing PSC acreages.
The workflow initially focused on post drill analysis of the existing wells whereby new complete petrophysical analyses for 74 exploration and appraisal wells were incorporated. Geological and geophysical interpretation focused on delineation of regional structural setting and development of a seismic sequence stratigraphic framework. This comprised of interpretation of key selected surfaces at wells and on seismic in the Oligocene and Miocene succession of the North Malay Basin. Upon completion of the tectono-stratigraphic interpretation, litho- and chrono-stratigraphy, sedimentology and sequence stratigraphy, analyses of seismic attributes and gross depositional environments (GDE), velocity model construction, depth conversion, isopach maps, regional overpressure trends; hydrocarbon play analyses could then proceed as supported by comprehensive petroleum system modelling and a regional CO2 study. Source rock hydrocarbon generation and migration timing are favourable throughout the Oligocene to Pliocene at all prospect levels. At lead and prospect scales, work on seismic inversion, AVO analyses and pore pressure modelling were undertaken preceding prospect volumetrics, risking and ranking. Primary target play types are predominantly comprised of stacked, stratigraphic structural combination traps of tidedominated estuarine reservoirs, deposited within a high frequency 4th-order sequence.
This comprehensive play based evaluation approach has successfully identified remaining hydrocarbon prospectivity, not only at deeper undrilled stratigraphic levels, but also at current producing shallow sequences. Several potential drillable prospects were further analyzed for future exploration, often with strong stratigraphic elements, as well as unconventional new play-types enabled by conceptual geological models and supported by existing data analysis and interpretation. Furthermore, a robust petroleum system modeling has enhanced and supported prospective plays in this basin, facilitating realistic yet-to-find resource estimates over the entire area, with good future prospectivity remaining in the area. Apart from the various collaborative technical studies carried out during the project, the imperative factor behind the success of this project was the synergy and co-operation among the team members, with regular technical and management reviews.
Promrak, W. (PTTEP) | Fongsuk, P. (PTTEP) | Uttareun, R. (PTTEP) | Sa-Nguanphon, S. (PTTEP) | Tubsrinuan, N. (PTTEP) | Matangkapong, K. (PTTEP) | Iamboon, J. (PTTEP) | Srisuriyon, K. (PTTEP) | Pabchanda, S. (PTTEP) | Sognnes, H. I. (PTTEP)
Combination and stratigraphic traps may contribute with significant gas reserves in Bongkot Field, Gulf of Thailand. However, such stratigraphic play cannot be easily defined as conventional seismic interpretation provides mainly structural information. To identify stratigraphic prospects in this area, a seismic pre-stack inversion and reservoir characterization study was carried out. The input dataset consisted of 365 km2 of 3D seismic, six wells, and interpreted time horizons. Following seismic pre-conditioning and rock physics analysis, wavelet extraction and well-ties were performed for each individual well, considering every input angle stack. Constrained by input time horizons, low frequency models were built based on well log and seismic stacking velocity. Inversion parameters were tested; subsequently, final inversion results were subjected to Bayesian classification to obtain a litho-facies volume. In addition, multi-linear regression was used to derive elastic-petrophysical relationships, to generate petrophysical property volumes. The final results included inverted elastic properties, classified litho-facies, computed effective porosity and Vshale volumes. By analyzing these results, several channel and deltaic/sand lobe features could be observed throughout the study area. Connected sand-filled channels with high porosity were mainly observed in the shallow section, as sand distribution appeared sparser and more isolated with increasing depth. Also, the predicted reservoirs in the deeper section were mostly filled with gas, while shallower sand bodies were mostly filled with brine. This observation implied that the high net-to-gross reservoir distribution in the shallow section can be a key factor that hinders effective trapping of hydrocarbons at this level. Since reservoir distribution plays a key role in hydrocarbon trapping mechanism, upside stratigraphic potential was identified from isolated gas-filled channels, mapped from seismic inversion products, to implement a more successful field development strategy in a mature field.
‘Play-based Pore Pressure Prediction’ is a new concept that considers overpressures and pore pressure prediction as being a fundamentally similar process to the ‘play-based exploration’ approach commonly used to search for hydrocarbons. For overpressures to exist, the right set of conditions needs to occur in the right order and timeframe. Just like a hydrocarbon play, overpressures need a source (generation mechanism), reservoir (the overpressured formation) and seal (ability to maintain overpressures over geological time). Current pore prediction methods do not consider overpressure over the geological timespan of a basin, and commonly result in overpressures being encountered in unexpected formations and depths, or at greater magnitude than anticipated, and has resulted in many drilling incidents.
Play-based pore pressure prediction involves undertaking pore pressure analysis in a similar holistic manner to how prospects are generated during hydrocarbon exploration. The process involves using basinscale geology to establish likely overpressure mechanisms and formations (akin to identifying sources, reservoirs and seals); determining timing of overpressure generation throughout burial history, and; identifying major events causing overpressure transfer or dissipation (akin to hydrocarbon generation, charge analysis and trap development). Regional concepts are used to develop models to determine the likely locations and magnitude of overpressure (akin to hydrocarbon fairways and plays). Finally, regional learning's are applied at the prospect scale to select the best methods to predict pressures for planned wells. The innovation, and added benefit, of this new and novel approach is that ‘play-based pore pressure prediction’ can also be used to identify successful new exploration plays. Herein, I present an example of ‘play based pore pressure prediction’ from the Malay Basin that was used to improve drilling safety, and developed a new play concept that has subsequently resulted in 3 successful discoveries.
Formation pressure plays as an important factor in any stage of E&P business. For drilling operations, formation pressure is a key factor controlling the well design as it can cause several drilling difficulties and direct impact to the well costs. Seismic technology up to date can help predicting the pore pressure zone more accurately. However, to narrow down the range of uncertainty, it is necessary to integrate subsurface geology such as basin evolution, depositional environment, facies distribution, well to well correlation etc.
In general, the pore pressure distribution of Bongkot concession is increasing basinward to southeast. In Greater Bongkot South (GBS), the over pressure is generally found throughout the area as most part of the GBS is located near to the basin center. Relatively lower pressure can be recorded along the active margin, in the Western Terrace trend, the western part of the GBS.
In vertical profile, the hydrostatic pressure in the GBS area, especially in the Western Terrace trend, can be found from mudline to lower unit 2D which is inline with more channel sand prone formation. The formation pressure is getting higher at near top unit 2C where the channel sand intervals are getting thinner with more bar sands intercalated. The formation pressure is peak at lower 2C and 2A and turning back to hydrostatic pressure at near top FM1. The maximum formation pressure in GBS is getting higher from NW to SE, i.e. 1.30 SG. EMW in NW area of GBS and laterally change to 1.90 SG. EMW in the eastern part in the Ton Koon-Ton Nok Yoong area where the basin depocenter is located. Drilling operations is become more challenging in GBS area as the well can encounter both gain and loss.
The regional pressure profile in GBS can be predicted using geophysical methods integrated with nearby well pressure data. However, in detail scale, there is high variation of pressure profile with several steps of pressure increasing at near top 2C. Ramping up shapes in the Western Terrace trend may have some relationship with formation interfingering and pinch out to the west where the paleo high is located. Fault seal and juxtaposition can be another factor of pressure released. Lateral facies change and fault conduit may release the pressure from abnormal high and leave the relative low pressure sands among the other high pore pressure zones.
The highly accurate prediction of formation pressure currently is still beyond the current tool and technology. Therefore back to basic knowledge of geology, well to well correlation, facies variation, juxtaposition, structural control plus the other related geological factors seems to be the best prediction method.
Combination of geological interpretation and drilling technique can help to drill successfully in high variation of pressure profile in GBS area. Understanding of subsurface condition in each particular area and subsurface interval can support preparation and optimization in drilling executing phase. Integrated drilling technique by minimizing the differential pressure seems to be the key success to drill in the high pressure variation area. Controlling rheology and mud properties to minimize loss circulation, slowing down the pump rate as well as integrating the other drilling technology shall be conducted. This integration of subsurface prediction and drilling best practice will lead to successfully drill the overpressure zone with minimum well cost.
Costam, Y. R. (PTTEPI Operating Company) | Fadjarijanto, A. (PTTEPI Operating Company) | Zakaria, Z. U. (PTTEPI Operating Company) | Setiawan, A. S. (PTTEPI Operating Company) | Pushiri, M. F. (PTTEPI Operating Company) | Carigali, C. Jiraratchwaro (PTTEPI Operating Company) | Lee, C. Y. (Halliburton) | Iyer, M. S. (Halliburton) | Zuilekom, T. V. (Halliburton) | Parashar, S. (Halliburton) | Bagir, M. (Halliburton) | W. Z .M, Ivan (Halliburton)
Gas fields in a Malaysia-Thailand joint development area (MTJDA) are well-known to have the presence of high CO2 concentration and high-temperature reservoir characteristics. Sophisticated tools are necessary to measures important data to support further development and reservoir management of this field. Thus, reservoir data, such as pressure and fluid type, become crucial in terms of achieving production targets. Fields operated by this operator are located in the North Malay Basin, a few hundred kilometers from the onshore border of Malaysia and Thailand.
High bottom hole temperatures (BHTs) limits data gathering runs and challenges associated with fresh water made it more crucial to identify and qualify fluid types for further field development. The extensive wireline formation pressure testing and sampling (WFPT&S) program is mandatory to evaluate the viability of field development. Additional challenges included low porosity-low mobility reservoirs where fluid collection at low contamination in reservoirs with elevated temperatures of approximately 410°F (210°C) is considered a necessity. This operator pioneers the use of novel hostile wireline formation testers globally. Reliable pressure and downhole fluid analysis data should lead to production optimization.
The ability of fluid characterization using a pump-out formation tester coupled with downhole fluid identification has been introduced to help improve decision making and provide real-time data and the capability to pump out high-temperature formation fluid and acquire samples that meet expected contamination levels. As a result, fluid contact, formation pressure, fluid type, reservoir mobility, and CO2 content, which are the primary drivers of production optimization and field development are able to be determined successfully. In addition, new deep reserves could potentially be discovered in the MTJDA concession that are economically accessible with extreme high-temperature tools.
This paper discusses the use of a novel hostile wireline formation tester to collect low contamination samples at a predetermined level in hostile reservoir conditions with elevated temperature of 410°F (210°C). Challenges, considerations, and results are detailed.
This novel tool has proven lower CO2 content than expected in deeper reservoirs with elevated temperature up to 410°F (210 °C). This is the deepest well ever drilled by this operator in a development drilling campaign.