Miocene Carbonate Reservoirs Research Articles

Applying machine learning for hydraulic flow unit classification and permeability prediction: case study from carbonate reservoir in the Southern part, Song Hong basin

Machine learning (ML) is an artificial intelligence (AI) that enables computer systems to classify, cluster, identify, and analyze vast and complex sets of data while eliminating the need for explicit instructions and programming. For decades, machine learning has become helpful for complex reservoir characterization such as carbonate reservoirs. Permeability prediction from well logs is a significant challenge, especially when the core data is rarely available due to its high cost. In this study, we aimed to bridge this gap by demonstrating the practical application of integrating Hydraulic Flow Units (HFU) and machine learning methods. Our goal was to provide a reliable estimation of permeability using core and wireline logging data in the complex Middle Miocene carbonate reservoir of the CX gas field in the southern part of the Song Hong basin. In the first step, due to the reservoir’s heterogeneity, the core plug dataset was classified into 5 HFUs based on the flow zone indicators (FZI) concept from the modified Kozeny-Carman equation using unsupervised machine learning - K-means method. The porosity - permeability for each HFU was defined after HFU clustering. In the second step, we designed three different workflows to predict permeability and HFU using supervised machine learning from a combination of core and log data. These workflows were rigorously test and compared with the core data. The most accurate result was chosen as the base, providing a high confidence level in our predictions’ reliability.

Integrated modelling of CO2 plume geothermal energy systems in carbonate reservoirs: Technology, operations, economics and sustainability

The rising CO2 content in the atmosphere calls for urgent decarbonization efforts. Carbon capture and storage (CCS) have proven effective in storing large volumes of CO2 in geological reservoirs. Nevertheless, challenges persist in identifying sustainable energy sources and efficient storage sites, especially in carbonate reservoirs. This study aims to characterize the Miocene carbonate reservoir in the Jintan Megaplatform, for CO2 storage and geothermal energy utilization. By integrating advanced technologies such as CO2 Plume Geothermal (CPG) with 3D seismic techniques, borehole analysis and numerical modelling, the study reveals the distribution of critical reservoir characteristics, including architecture, heterogeneity, karstification, fractures, porosity, permeability, temperature and pressure that are paramount for CO2 plume and energy production. The reservoir is estimated to store over 31 Gt of CO2, produce 3.824 × 1018 J of geothermal energy and ⁓44.3 GW of power. This power output can be utilized for electrification of the CCS operations, industrial and municipals, potentially generating over $1.4 billion in revenue. A flow-through model has been proposed to improve energy efficiency, reservoir management, and risk mitigation. This study advances to achieving net-zero targets and the United Nations Sustainable Development Goals on clean energy, climate action and sustainable communities.

Reservoir Rock Discrimination Based on Integrated Image Logs and Petrographic Analysis: A Case Study from the Early Miocene Nukhul Carbonate, Southern Gulf of Suez, Egypt

AbstractThe discrimination of rock types within the limestones and dolostones of the Nukhul Formation in the West Younis Field (Gulf of Suez Basin, Egypt) presents significant challenges due to their multi-scale compositional and diagenetic heterogeneity, diverse pore types, complex microstructures, and limited core data. This study aims to characterize the carbonate reservoir of the Early Miocene sediments and establish distinct reservoir rock types by employing textural analysis, geological interpretations (i.e., structural interpretation, fracture analysis, reservoir characteristics) using advanced imaging tools, and petrophysical measurements to model porosity/permeability profiles across the reservoir. A new dataset was obtained from the latest exploratory well in the West Younis Field, incorporating microresistivity and acoustic image logs, well logs, nuclear magnetic resonance (NMR) tools, and drill cutting petrographic analysis. The integration of these datasets provided a comprehensive understanding of the properties of the Early Miocene carbonate reservoir. Based on image logs, the carbonate facies were divided into four reservoir units. Petrographic evaluation further classified two facies (A and B) based on diagenetic factors controlling reservoir quality. The results revealed the occurrence of multiple phases of dolomitization, which influenced the reservoir quality. Early-stage dolomitization enhanced reservoir quality, while late-stage idiotopic dolomite crystal growth diminished it. The study also provided comprehensive information on the original rock fabric/texture, diagenetic processes, porosity types and origins, as well as the spatial distribution of pores (permeability index) within this complex carbonate reservoir. By employing an integrated technique, this study successfully differentiated the carbonate reservoir into distinct rock types, leading to improved reservoir characterization and field development. Additionally, the findings contribute valuable insights for the development and exploration of the Early Miocene carbonate section in the southern Gulf of Suez.

The implications of structural control on the miocene carbonate reservoirs of Bakr-Al Hamd oil fields, Gulf of Suez

The present work aims to provide a tectonostratigraphic model of the Miocene carbonate reservoirs accumulated in Bakr-Al-Hamd ridge to help unlock an estimated statistical yet-to-find over 10 MMbbl of oil. The structural ridge is located in the western central Gulf of Suez and the hydrocarbon exploration within this NE-dipping structural high began in 1951. The model integrated several interpreted 3-D seismic volumes and their attributes, a complete set of well-log data, borehole images, and the resultant extensional structures from the natural and physical models. The structural model proposed the following: (1) a major gulf-parallel curved and faulted detachment between the two differentially strained sections of Miocene and Pre-Miocene sediments which were distinguished by seismic attributes and confirmed by borehole images, (2) the synthetic Gulf-parallel faults which represent footwall collapsing structural style of extensional faults, delineated Al Hamd Miocene Nullipore carbonate reservoir, (3) south-westward dislocation of the western gulf-parallel boundary fault of Al Hamd Nullipore facies and its allocation at the present-day shoreline, (4) three classification of the Miocene carbonate reef were interpreted; fringe reef in Bakr ridge, barrier reef in Al-Hamd, and patch reef in the intra-field. The achievements of the present study prompted exploration activity and two discoveries were announced in 2021 and 2022 in the vicinity of Bakr and Al-Hamd intra-fields. The recent discoveries penetrated more than 200 m of Miocene carbonate reef and dolomitic reservoirs accumulated on the detachment surface. The present study workflow could be used in similar petroliferous rift basins to maximize hydrocarbon resources, enhance production performance, and revive brownfields.

Evaluation of Carbonate Reservoir with Integration of Petrophysical Analysis and Seismic Impedance Inversion in Banggai Basin, Sulawesi

Banggai Basin is controlled by the collision between Banggai-Sula micro-continent and East Sulawesi ophiolite belt, forming a thrust-sheet anticline structure that has potential to trap hydrocarbon. The Siotu-1 well was drilled right into the thrust-sheet anticline structure targeting Miocene carbonate platform layer. The same structure has proven to be an oil trap at the Tiaka oilfield which is located adjacent to the Siotu-1 well. This study aims to evaluate the presence of hydrocarbon in the Siotu-1 well with characterization of the Miocene carbonate reservoir. It is carried out by integrating petrophysical analysis from the Siotu-1 well log data and 2D seismic impedance inversion of the Tarib-1 line. Five reservoir zones have shale content values range of 21.91-37.53%, effective porosity values range of 9.7-14.62%, water saturation values range of 88.5-98.27%, and permeability values range of 2.53-8.16 mD. The results of the porosity calculation are validated by the model of seismic inversion where the reservoir zone with an acoustic impedance in the range of 7600-13450 ((m/s)/(g/cc)) is a carbonate layer with fair to excellent porosity (10 to> 25%) and reservoir zone with acoustic impedance values range of 13450-16200 ((m/s)/(g/cc)) as carbonate layer with poor porosity (< 10%). The net pay zone in reservoir zone 4 with a thickness of 4.5 feet and a net-to-gross of 0.006 are shown as the lumping result. It is concluded that Miocene carbonate reservoir in the Siotu-1 well met the criteria as a good reservoir rock but insignificant of hydrocarbon potential for further development.

Developing a Saturation Height Function (SHF) for the classified Hydraulic Flow Unit, a case study from the Middle Miocene Carbonate reservoir in the Song Hong Basin, Vietnam

The Middle Miocene carbonate is the main gas bearing reservoir in the southern part of the Song Hong basin. Carbonate reservoirs present challenges for engineers and geologists to characterize because of their complexity due to depositional and diagenetic processes. The log based calculated water saturation Sw for this complex carbonate reservoir bears a lot of uncertainties due to its heterogeneity that strongly affects to m and n values in the water saturation equation. As the calculated Sw strongly affects the Hydrocarbon Initially In Place (HIIP) estimation, the production performance prediction, etc., the alternative method using the Saturation Height Function (SHF) based on the capillary pressure was introduced. The SHF building process uses the combination of the result of HFU classification and permeability prediction given by machine learning methods, which have become a very useful tool for complex reservoir characterization such as carbonate reservoir for decades. Our obtained results allowed us to subdivide the carbonate reservoir into 5 Hydraulic Flow Unit (HFU) by using unsupervised machine learning methods, and then the capillary pressure (Pc) curves were classified and a proper saturation-height function using Skelt Harrison equation was assigned to individual HFU after testing with common SHF equations. The HFU number for each individual point was predicted based on the log data measured along the borehole using the supervised machine learning techniques while the Sw was calculated using the chosen SHF model and the FWL defined on log curves and pressure data from RCI measurement. The Sw computed from the SHF model is reliable and can be used for water saturation estimation for the whole field for known FWL and predicted HFU numbers.

Improving carbonate reservoir characterization by applying rock typing methods: a case study from the Nam Con Son Basin, offshore Vietnam

Understanding the permeability-porosity relationships is the key to improving reservoir prediction and exploitation especially in carbonate reservoirs, which are known for their complex textural and diagenetic variation. Rock type classifications have long been proven to be an effective technique for establishing permeability- porosity relationships, enhance the capability to capture the various reservoir flow behavior and prediction for uncored reservoir zones. This study highlights some of those practical and theoretically-correct methods, such as Hydraulic Flow Unit (HFU); Global hydraulic element (GHE), Winland’s R35 method, Pittman method, Lucia method. They are proposed and tested for identification and characterization of the rock types using a database of 555 core plugs from the Miocene carbonate reservoir in the Nam Con Son basin. It is a large isolated carbonate build-up structure which were deposited within a shallow marine platform interior and are dominated by coral, red algal and foraminiferal packstones, wackestones and grainstones. Hydrocarbons in this reservoir have been found in the upper most part of the late Miocene formation. Conventional core data were first used to define and display the cross plot of permeability and porosity. Different charts and cutoff thresholds were used to classified, defined number of rock type and the linear and non-linear equations were established. The predicted core permeability was calculated using different methods and compared with the actual core permeability for each rock type. The predicted reservoir rock type and permeability predictions of HFU method was recognized to give better matching of measured core permeability with coefficient of more than 89%.

Integrated Carbonate Rock Type Prediction Using Self-Organizing Maps in E11 Field, Central Luconia Province, Malaysia

Reducing uncertainty in 3D carbonate rock type distribution is a critical factor that profoundly impacts field development for hydrocarbon or carbon capture and storage (CCS) projects. Miocene carbonate reservoirs in the Central Luconia offshore region are economically important global gas reservoirs. The nature of these carbonate rocks can be visually distinct in the core and the multiscale reservoir heterogeneity might vary in scale from the 100-m scale to the sub-millimeter scale. This work presents a series of steps workflow to obtain spatial information about the organization scheme of carbonate rock types, and capture the most important petrophysical and sedimentary controls on rock property distribution in the E11 field, a carbonate buildup, located in Central Luconia Province, offshore Malaysia. The spatial data were generated from a supervised neural Kohonen algorithm. The rock types predicted with this workflow were propagated using IPSOM probabilized self-organizing maps SOM. This tool is used for classifying multivariate data samples according to “patterns” or multivariate responses. The workflow includes several steps: A Step 1—Core data description, B Step 2—Thin section description, C Step 3—Well log interpretation, and D Step 4—IPSOM probabilized self-organizing maps for facies prediction SOM. The depth plots of the predicted rock type showed close correspondence to the core-based rock types in terms of the stratigraphic organization of tight and reservoir layers, proportions, and juxtaposition. This result is sufficient to merit the application of the rock type logs into a future porosity model of the E11 field, and to understand the lateral and vertical distribution of tight and reservoir rock types of distribution. The results can be used to build a future realistic digital twin of the subsurface, and in digital geological modeling.

Seismic expression of miocene carbonate platform and reservoir characterization through geophysical approach: application in central Luconia, offshore Malaysia

A substantial proportion of proven oil and gas reserves of the world is contained in the carbonate reservoir. It is estimated that about 60% of the world’s oil and 40% of gas reserves are confined in carbonate reservoirs. Exploration and development of hydrocarbons in carbonate reservoirs are much more challenging due to poor seismic imaging and reservoir heterogeneity caused by diagenetic changes. Evaluation of carbonate reservoirs has been a high priority for researchers and geoscientists working in the petroleum industry mainly due to the challenges presented by these highly heterogeneous reservoir rocks. It is essential for geoscientists, petrophysicists, and engineers to work together from initial phases of exploration and delineation of the pool through mature stages of production, to extract as much information as possible to produce maximum hydrocarbons from the field for the commercial viability of the project. In the absence of the well-log data, the properties are inferred from the inversion of seismic data alone. In oil and gas exploration and production industries, seismic inversion is proven as a tool for tracing the subsurface reservoir facies and their fluid contents. In this paper, seismic inversion demonstrates the understanding of lithology and includes the full band of frequency in our initial model to incorporate the detailed study about the basin for prospect evaluation. 3D seismic data along with the geological & petrophysical information and electrologs acquired from drilled wells are used for interpretation and inversion of seismic data to understand the reservoir geometry and facies variation including the distribution of intervening tight layers within the Miocene carbonate reservoir in the study area of Central Luconia. The out-come of the seismic post-stack inversion technique shows a better subsurface lithofacies and fluid distribution for delineation and detailed study of the reservoir.

New constraints on the tectonosedimentary evolution of the offshore San Pedro Basin (southeastern Dominican Republic): implications for its hydrocarbon potential

Abstract The San Pedro Basin (SPB) is located at the southeastern margin of Hispaniola Island (Dominican Republic and Haiti). It is the largest offshore basin of the Dominican Republic with an extension of 6000 km 2 . The basin has a maximum water depth of 1600 m and is positioned to the rear of the Muertos Thrust Belt (MTB). The SPB is bounded to the west by the Azua Basin which has a proven petroleum system and small oil production has been recovered from the Maleno and Higuerito fields. While in the scientific literature the SPB and the Azua basins have been considered as disconnected sedimentary systems, our current study suggests both that shared a common tectonic evolution and therefore the presence of an untested petroleum system in the SPB can be expected. We have carried out a detailed review and synthesis of the onshore systematic geological mapping (the SYSMIN I and II programmes) together with the integration of a large volume of subsurface geophysical data. This includes analysis of 60 exploration wells provided by Banco Nacional de Datos de Hidrocarburos (BNDH) of the Dominican Republic, processing of new 2D multi-channel seismic data from the Spanish Research Project NORCARIBE, reprocessing of legacy seismic profiles, and interpretation of gravity and magnetic data. Our results have led us to propose a new evolution model for the SPB. The basement of both basins consists of Cretaceous sedimentary and volcanic rocks of intra- and back-arc settings. A change in the stress regime in the Campanian led to partial inversion of the basement units favouring the deposition of two main sequences of Campanian–Maastrichtian and Paleocene?–Eocene age in a submarine foreland setting. Due to collision between the Carbonate Bahamas Province and Hispaniola in the middle Eocene, compressional stresses were transferred to the south where Cretaceous and Paleogene sediments were deformed, forming the current configuration of the MTB and generating a new accommodation space where the SPB has developed since upper Eocene–Oligocene until Present. While the Azua Basin was finally exhumed after the Miocene–Pliocene, most of the SPB continued as an actively subsiding basin. This new model has allowed identification of the main elements of the petroleum system in the SPB: a mature Upper Cretaceous source rock; and Oligocene–Miocene carbonate and clastic reservoirs interbedded with sealing shales and marls. Main traps (structural and stratigraphic) are of Oligocene–Miocene age and their formation seems to be synchronous to oil generation. While the main elements of the petroleum system seem to be present in the basin, timing is a key issue that must be addressed and assessed in any future exploration in the basin.

A review of the Oligo–Miocene larger benthic foraminifera in the Zagros basin, Iran; New insights into biozonation and palaeogeographical maps

Developing a more precise time framework in any hydrocarbon-bearing basin is potentially of great value to geologists and reservoir modelers for better understanding the hydrocarbon reservoir zonation, and identifying unconformities. In the Asmari Formation, which is the most important Oligocene–Miocene carbonate reservoirs in Iran, broad time zonation is generally used based on larger benthic foraminifera (LBF). In this study, the biostratigraphic zonation of the Asmari intra-shelf basin is re- evaluated based on the spatial and temporal distribution of LBF (i.e., different species of Nummulites, Eulepidina, Archaias, Spiroclypeus, Miogypsinoides, Miogypsina, and Borelis) as well as Sr isotope datasets. This research proposes a new zonation to improve time resolution in the Oligocene and explains the effects of environmental factors on some index fossils and the limited range of some key fauna. The newly proposed zonation consists of one biofacies and nine biozones occurring throughout the Rupelian to Burdigalian allowing differentiating Oligo-Miocene stages, and tuning the chronostratigraphic framework of the Oligocene–Miocene deposits. Moreover, based on this new biozonation, regional-scale palaeogeographical maps of the Asmari intra-shelf basin during Rupelian-Burdigalian were officially established.

Early Miocene Carbonate “G-0” Distribution Analysis Using Spectral Inversion

“KHM” structure is one of PT. Pertamina EP oil producing field in Subang, North West Java Basin. One of the hydrocarbon producers of this structure is located in thin bedded Early Miocene carbonate reservoir which in Upper Cibulakan Formation. The thin bedded reservoir becomes a challenge because the post stack time migration seismic resolution can’t resolve the each layer. To distinguish and delineates the reservoir’s lateral continuity needed spectral decomposition analysis. This analysis obtained 3 best frequencies to acquire a better imaging which known as tuning cube, they are 15 Hz, 20 Hz, and 25 Hz . Furthermore, these frequencies were blended to get spectral decomposition volume. The volumes have same frequency and amplitude with post stack time migration seismic data, so it can be used for further interpretation. To predict the distribution and depositional facies of Early Miocene carbonate, performed seismic interpretation by using model based acoustic impedance inversion on spectral decomposition volume and porosity analysis. The result of this study suggest the lateral distribution of Early Miocene carbonate can be characterized. Acoustic impedance zone that associated with porous carbonate have ranges values of 8050 - 9800 gr/cc ml. This is supported by petrophysics analysis that generates porosity values of 7.4 - 13.9 % in this zone. The relationship of both analysis based on the correlation of well, known that porous carbonate was deposited on a shelf margin facies.

What matters for flow and recovery in carbonate gas reservoirs: Insights from the mature Central Luconia Province, offshore Sarawak, Malaysia

Miocene carbonate reservoirs in Central Luconia, offshore Sarawak, Malaysia, have been delivering gas for over 30 yr. In this paper, learnings from that period of production are used to understand the key drivers affecting flow during production and recovery optimization in existing fields as well as development decisions for new discoveries. The large data set, generated over more than 40 yr, was analyzed in a consistent manner through a holistic database, constrained by a stratigraphic framework, to allow reservoir units to be compared like-for-like (“integrated knowledge base” [IKB] concept). Carbonate reservoir heterogeneities impacting flow are grouped into “horizontal–heterogeneities”—argillaceous flooding layers and exposure-related karst—and “vertical–heterogeneities”—large-scale architectural elements, found especially along platform margins. Both types of heterogeneities control water ingress during production and influence the recovery mechanism. Argillaceous flooding layers can act as baffles, holding back water rise during production, or can form pressure compartments. Long-lived, fault-bounded reef margins, carbonate shoals, islands, and karsts can be vertical conduits for aquifer inflow. Platform shape and architecture impact column height and hence recovery efficiency. Additional drivers impacting recovery were found to be gas-column height, aquifer size and permeability, pressure connection to neighboring fields, and field development concepts. All drivers identified impact decisions throughout the field life, e.g., well count and design, intervention capabilities, evaluation and mitigation of early-water breakthrough, reservoir management, selecting enhanced recovery methods, and abandonment pressure. The IKB allowed to derive “big rules” on what matters for flow, which were used to decide on development strategies for greenfields in Central Luconia. The presented outcomes can be extrapolated to comparable carbonate systems, whereas the IKB approach can be adapted and applied to other mature basins and reservoir types where equally vast and historic data sets are awaiting to be used in the current era of digitalization.

New approach towards the classification of microporosity in Miocene carbonate rocks, Central Luconia, offshore Sarawak, Malaysia

Microporosity is recognized as a significant concern in limestone reservoirs throughout the world because it presence can highly complicate the hydrocarbon estimation and production. Numerous studies around the globe emphasises on the physical appearance, occurrence, and abundance of microporosity, but no published study has been emphasises on the presence of microporosity in Miocene carbonate reservoirs. Miocene carbonates from Central Luconia, offshore Sarawak, Malaysia, contains a significant amount of micropores, which occurs in grain, matrix, and cement. For a better understanding of the presence of micropores, it is necessary to consider grains, matrix, cement, and pore types. Based on the qualitative and quantitative knowledge of these components a classification of micropores is proposed and their effect on reservoir quality. These results can reduce the number of the assumption made about the internal rock connectivity and quality.For quantitative analysis, 32 high-resolution images of each thin sections were taken under the transmitted light microscopy. Succeeding these 32 images were stacked together as a photo panel to enable quantifying the amount of grain, matrix, cement, pore types and macroporosity using Digital Image Analysis and J.Microvision software. Furthermore, Field Emission Scanning Electron Microscopy images were also used for the measurement of crystallometry of micrite particles, classification of micrite particles and the micropores.Eight facies scheme is introduced based on the detailed lithofacies study of five wells. The qualitative observation of thin sections unveiled that corals, red algae, green algae, foraminifera, echinoderms, sponge, bivalve, and bryozoans are the most dominant components. Foraminifera, red algae, and corals are the far most dominant components covering almost 50% of the total intervals. Regarding porosity types, the mouldic porosity is the far most dominant pore types with converting the total 50% of the interval. Lithofacies observed in these wells indicate a good reservoir quality, but diagenesis plays a vital role in enhancing or reducing their porosity and permeability. Most of the depositional textures of the reservoir are leached, making this location unique to study facies distribution and diagenetic history.Result exhibits that the micrite particles are classified into five classes, which are very fine, fine, medium, coarse and very coarse, with a diameter of 0.1–2 μm, 2–4 μm, 4–6 μm, 6–8 μm and 8–10 μm respectively. The texture and morphology of micrite microtexture are classified into six classes. Among these six classes, rounded, subrounded, trigonal, rhombic (micro-sub)-polyhedral micrite are representing porous micrite particles, whereas fitted bounded subhedral, and fitted fused anhedral are interpreted as tight micrite particles. Furthermore, five micropores classes are introduced based on the size of these particles. The empirical porosity-permeability relationship is affected by the presence of microporosity and its influences the assessment of ultimate recovery of hydrocarbons in Central Luconia, offshore Sarawak, Malaysia.

Hydrocarbon migration in the Zagros Basin, offshore Iran, for understanding the fluid flow in the Oligocene–Miocene carbonate reservoirs

Kuh-e Mond Field is a conventional heavy oil resource in the Zagros foreland Basin, Iran, produced from the fractured carbonates partially filled by dolomite, calcite, and anhydrite cement. Vitrinite reflectance data from carbonate reservoir suggest low-maturation levels corresponding to paleotemperatures as low as 50 °C. The observed maturation level (<0.5% Rmax) does not exceed values for simple burial maturation based on the estimated burial history. Oil inclusions within fracture-filled calcite and dolomite cement indicate the key role of these fractures in oil migration.The fluid inclusion temperature profiles constructed from the available data revealed the occurrence of petroleum in dolomite, calcite, and anhydrite and characterize the distinct variations in the homogenization temperatures (Th). Fluid inclusions in syntectonic calcite veins homogenize between 22 °C and 90 °C, showing a salinity decrease from 22 to 18 eq. wt.% NaCl. Fluid inclusions in anhydrite homogenize at <50 °C, showing that the pore fluids became warmer and more saline during burial. The Th range in the calcite-dolomite cement depicts a change in water composition; therefore, we infer these cements precipitated from petroleum-derived fluids. The microthermometry data on the petroleum fluid inclusions suggest that the reservoir was filled with heavy black oils and high-salinity waters and indicate that undersaturated oil was present in a hydrostatically pressured reservoir.The Th data do not support vertical migration of hot fluids througout the section, but extensive lateral fluid migration, most likely, drove tectonically dewatering in the south or west of the pool.

Modern analogues to heterogeneous Miocene carbonate reservoirs of the South China Sea

Bernard J. Pierson, Aicha Chalabi and Ani Aiza Asha’ari argue that present day analogues may provide useful tools to represent and even quantify reservoir heterogeneity. Studies of recent carbonate platforms in the Celebes Sea, east of Sabah, illustrate both the complexity of lateral facies distribution on individual platforms and the variability from one platform to another.

Transverse segmentation of the Baram-Balabac Basin, NW Borneo: refining the model of Borneo's tectonic evolution

The West Baram Line separates NW Borneo’s two petroleum systems. Oligocene sandstone and Lower Miocene carbonate reservoirs of the gas-prone Luconia system lie SW of that line. Northeast of the West Baram Line, the oil-rich Baram-Balabac Basin produces from Middle Miocene to Early Pliocene sandstones deposited in a foreland basin on the western side of the mountainous interior of Borneo. On the present-day shelf exploration efforts spanning nearly four decades have focused on the Champion and Baram deltas and associated extensional growth fault structures. Many of these structures have experienced youthful inversion owing to ongoing tectonic shortening. Recent discoveries prove this petroleum system extends into deep water beyond the modern shelf edge where an active fold-thrust belt has formed above autochthonous rifted continental crust of the Dangerous Grounds province in the South China Sea. New regional mapping (c. 100 000 km2) integrating seismic, borehole and gravity data shows that the Baram-Balabac Basin is segmented into four structural domains whose boundary zones trend NW-SE similar to the strike of the West Baram Line. Domain boundaries appear to control the position of the basin’s palaeoshelf edges, turbidite depositional systems, major unconformities and the position of the basin’s largest fields. These observations suggest that the domain boundaries are the expression of deep structures, probably within the underlying rifted continental crust. Two of the domain boundaries can be projected onshore to align with fault systems separating contrasting geological elements indicating they represent features of tectonic interest. The onshore geology of NW Borneo represents the early history of the Baram-Balabac Basin. The onshore geology is reviewed and new outcrop, biostratigraphic and palaeomagnetic data from Sabah are discussed in light of current models for the region’s tectonic evolution. A hybrid model is proposed in which the Baram-Balabac Basin post-dates the Sarawak Orogeny. The Sarawak Orogeny, which appears to be more regionally extensive than previously believed, is attributed to Eocene to Early Oligocene collision of the Dangerous Grounds and Reed Bank with Sabah and Palawan. In the proposed model Oligo-Miocene subduction of oceanic crust under NW Borneo is minimal. The Sabah Orogeny and younger inversion events are related to underthrusting of the Dangerous Grounds driven by both the opening of the South China Sea and by NW-directed subduction beneath SE Sabah in the Semporna-Dent Peninsula. In this context the structural complexity of the Baram-Balabac foreland basin reflects the adjustment of deep crustal blocks to far-field tectonic stress.

ABSTRACT: Integration of geological and geophysical data to reconstruct depositional models of Miocene carbonate reservoirs from Southeast Asia

ABSTRACT: Integration of geological and geophysical data to reconstruct depositional models of Miocene carbonate reservoirs from Southeast Asia

ABSTRACT: Computer Simulation of Carbonate Facies Distribution and Shallow Diagenetic Process of Miocene Carbonate Reservoirs, Southeast Asia

ABSTRACT: Computer Simulation of Carbonate Facies Distribution and Shallow Diagenetic Process of Miocene Carbonate Reservoirs, Southeast Asia

Architecture of Miocene carbonate reservoirs in South East Asia

Architecture of Miocene carbonate reservoirs in South East Asia