A geostatistical seismic pre-stack inversion was carried out over a producing gas and condensate field in the Gulf of Thailand, North Malay basin. As the main reservoirs are thin-bedded stacked fluvial deltaic sands of Miocence age, detailed mapping of reservoir distribution was challenging due to limited seismic resolution. To overcome such challenges, a pre-stack geostatistical inversion was initiated. The input dataset consisted of six wells and 250 km2 of 3D seismic data. The well log data passed through rigorous QC and rock physics analysis, while the seismic data were subject to preconditioning to ensure improved CDP gather flatness and signal-to-noise ratio. Starting from geostatistical modeling, the inversion generated multiple detailed realizations of lithology and elastic properties based on Bayesian Inference and Markov-Chain Monte Carlo methods. Statistic of multiple resulting realizations also implied a range of possible solutions of this non-unique inverse problem. In addition, petrophysical properties were simulated by using statistical relationships between inverted elastic and petrophysical properties. By integrating high frequency well logs with low frequency seismic, the geostatistical inversion process provided high vertical resolution and captured spatial variations of the various lithology types and their respective elastic properties. Since a majority of the stacked gas sand reservoirs in the area were below the tuning thickness, the geostatistic inversion results provided significantly improved insight to facies distribution. According to blind well results, precision of net pay estimation provided by the geostatistical inversion improved from 40% to 83%, compared to predrilled prognosis; while, pay estimation uncertainty was reduced by 30%. The generated petrophysical volumes also showed more detailed spatial variation, and can be used to improve in-place volumetric calculations and support field development planning.
Adnan, M. Mohd (Carigali-PTTEPI Operating Company) | Ismail, W. Wan (Carigali-PTTEPI Operating Company) | Kaewtapan, J. (Carigali-PTTEPI Operating Company) | Setiawan, A. S (Carigali-PTTEPI Operating Company) | Tanprasat, S. (Carigali-PTTEPI Operating Company)
A comprehensive technical evaluation was conducted after the completion of six exploration and appraisal wells to assess the future petroleum potentials in North Malay Basin, offshore Malaysia-Thailand Joint Development Area (MTJDA). This paper focuses on major discoveries and findings from key wells, namely Well-E3, Well-A2ST, and Well-T3 to better understand the petroleum potentials for the subsequent development planning.
Well-E3 and Well-A2ST were drilled to investigate the stratigraphic trap play in the eastern flank of MTJDA and to explore the hydrocarbon potential in deeper depositional sequence below DS10 interval. The seismic dataset and amplitude analyses were used to identify channel fairways and qualitatively predict sand presence for well planning optimization. Both wells encountered gas-bearing sands with proven stratigraphic trap style, requires channel orientation oblique with the axial anticline structure. Full integration of well log dataset, formation pressure test and seismic attribute analyses have proven the exploration intervals with gas-bearing sands discoveries. In addition, rock physics analysis was performed to differentiate gas from wet sand and coals.
Well-T3 was drilled in the western flank to appraise the seismic anomaly associated with hydrocarbon sand and to investigate the CO2 content in the southernmost extension of hydrocarbon accumulation. The anomaly is observed as two distinct sand fairways of channel-bar complex. The northern lobe was dissected by deep seated fault system with high CO2 content. The southern lobe appears to be free from deep seated fault system. Well-T3 was drilled in the area where CO2 pathways was expected to have no connection with deep seated fault system and lower CO2 content than the main area. Formation pressures, samples and seismic anomaly supported the hypothesis that the northern and southern culminations are not connected with significant stratigraphic heterogeneity interpreted. An important oil discovery was also observed from pressure gradient and samples as the first oil discovery in the western flank.
Full integration of the well log dataset, formation pressures, seismic attribute analyses and rock physics modeling have resulted in an improved understanding of reservoir distribution and reduced the degree of uncertainty in reservoir connectivity, thus allowing a more robust development strategy. The new discoveries of proven stratigraphic trap in the eastern flank with deeper hydrocarbon culminations and proven oil discovery in the western flank with enhanced understanding of CO2 content have triggered more future petroleum potentials in MTJDA acreage.
The classic tripartite parasequence set scheme is widely used in coastal plain sequence stratigraphic interpretations which respond to a relative sea level cycle. The Highstand System Tract (HST) is immediately followed by a Lowstand Systems Tract (LST). The ensuing Transgressive System Tract (TST) accompanies the flooding stage, but there is no corresponding parasequence set during a fall in relative sea level fall. In theory a Regressive Systems Tract (RST), would be produced during a relative seal level fall, where it would erode and replace portions of the upper HST and would lie beneath in time (though not in the stratal record) the ensuing LST and would be characterized by offlap and basinward shift in facies (e.g. the FSST distal clastic wedges descrbed by Plint and Nummedal, 2000). However, as preserved deposition is minimal during the fall, an RST would be less well-preserved in a deltaic setting. The purpose of this study is to demonstrate that the RST which responds to a drop in base level indeed can be found in ramp coastal plain settings, where they are represented as fluvial terraces. The example comes from offshore Thailand.
The neglect of the RST in stratigraphic interpretation can be attributed in part to the initial evolution of the systems tract concept and subsequent confusion of this concept in different theories concerning the effects of base level changes upon depositional sequences (Pigott et al., 2011).
First, owing to the difficulty of recognition of offlapping strata in early 2D seismic sections, the subdivision of sequences into the classic component systems tracts was first presented by Posamentier and Vail (1988) where a highstand was immediately followed by lowstand. The limited recognition of sediments deposited during relative sea-level fall led to the early representation of relative sea-level fall as 'instantaneous' and the asymmetry of the relative sea-level curve was later attributed to incomplete preservation of the sedimentary record with the classical definition of prograding, aggrading, and retrogradational system tracts which were then defined as the parasequence sets termed HST, LST, and TST (van Wagoner et al., 1988).
Second, in consideration of a complete sea level cycle, as several previous workers have addressed the sea-level falling stage in different theories (Catuneanu, 2007), there exists a general lack of a unanimous agreement on the division of base level falling from onset to the end. There are four opinions: (1) early LST fan (Haq, 1987; Posamentier, 1988; and Galloway, 1989; etc.); (2) Late HST (vanWagoner 1995, etc.); (3) FSST (Hunt and Tuck, 1995, etc.); (4) RST (Embry, 1993, etc.).