Top Seal Research Articles

Site characterization of the Endurance CO 2 store, Southern North Sea, UK

The Endurance saline aquifer CO 2 store in the UK North Sea is the planned storage site for CO 2 emissions that will be captured from the East Coast Cluster. The site has been characterized to assess its suitability for injectivity, containment and capacity. The injection target is the Early Triassic Bunter Sandstone Formation, consisting of fine-grained sandstones deposited in fluvial, lacustrine and playa lake environments that were subject to repeated aeolian and fluvial reworking. The sandstones have excellent reservoir quality and are likely to be well connected due to the lack of preserved heterolithic layers. The trap is a large, four-way dip-closed anticline, sealed by mudstones and evaporites of the Middle Triassic Dowsing Formation. The top seal sediments are laterally extensive and geomechanically strong, and faulting observed in the overburden does not appear to connect to the reservoir, providing confidence that CO 2 containment will be secure. The risk of leakage through existing legacy wells is assessed as low. The maximum effective CO 2 storage capacity is c . 450 Mt: Phase 1 development of 100 Mt is equivalent to a storage efficiency factor of 3%, which is achievable without the need for brine production. First injection is planned from 2027.

Fault and top seals 2022: a perspective

This short article summarizes the thematic collection comprising key results from the Fault and Top Seals Sixth EAGE conference.

Compositional controls on the Lower Cretaceous Rodby Shale pore structure and surface area: a planned CCS top seal caprock for the Acorn storage site

Fine-grained lithologies above CCS reservoirs cannot automatically be assumed to be mineralogically stable, or high quality top-seals to highly pressured CO2 as saline aquifer have previously contained hydrostatically pressured water. We have investigated the mineralogy, pore systems and surface area characteristics of the Lower Cretaceous Rodby Shale, the caprock to the Captain Sandstone at the UK's planned Acorn/Goldeneye CCS site. Rodby Shale core was logged and analysed by XRD, light microscopy, and SEM. Grain size was measured using laser particle size analysis. Mercury intrusion porosimetry and nitrogen adsorption analysis were used to characterise the pore network. The Rodby is smectite-rich and contains abundant calcite as well as quartz silt with small quantities of chlorite and plagioclase. Calcite was sourced from benthic microfossils, locally recrystallised to create a pore-filling cement. The mean pore throat and pore body diameter are about 17 nm putting the Rodby in the mesopore range and suggesting a predominance of slit-like pores. There are three lithofacies in the Rodby Shale: (i) high surface area clay-rich shale, (ii) low surface area calcite-rich shale, (iii) intermediate surface area quartz-rich. if the second lithotype encountered CO2, then the resulting calcite dissolution would lead to increasing surface area of the remaining shale. The Rodby Shale has good potential to be an effective barrier for CO2 escape, based on assessments of diffusion rate and post-breakthrough advection rate as well as stability and sealing assessments.

Evaluation of top seal capacity by pseudo-capillary pressure model in Suriname offshore Basin

Drilled well data and 3D seismic data are integrated to model the seal capacity of the Late Campanian- Maastrichtian mudstone in the exploration Block 52 operated by PETRONAS Suriname Exploration & Production BV. The study proposes simple relationships between interval velocity and porosity, porosity against permeability, and normal compaction of the mudstone with depth, based on the drilled well data. The most likely model of the top seal capacity suggests a maximum column height to be in the range of 330 – 350 m in the study area for gas. The model also suggests a gradual increase in the top seal risk towards the northeastern direction of the study area which may be due to the effect of sediment fairway from the nearby Demerara High. On the other hand, an increasing trend of top seal capacity towards the southwestern side of the block relates to the possible effect of the thicker deposition of transgressive fine-grained package with more compaction resulting in a decreasing trend of porosity and permeability of the mudstone.

Fluid characterization of oil and gas fields: implications for fault and top seal integrity assessment

Integrity of fault and top seal is a key factor that affects hydrocarbon fluid phase distribution in the subsurface. Mapping fluid property distribution can therefore provide important tools towards assessing seal integrity and trapping mechanisms – two of the most critical elements in petroleum systems analysis towards optimzing exploration and development strategies. This is best achieved by proper fluid characterization that integrates fluid geochemistry and pressure–volume–temperature (PVT) data to identify equilibrated and disequilibrated fluid gradients. Fields from Paleozoic and Mesozoic basins in the Arabian Peninsula at different stages of delineation, appraisal, development and management are discussed as examples to demonstrate the role of fluid characterization in aiding the evaluation of top, lateral and fault seal integrity, and in providing insights into the sealing and buffering effects of reservoir heterogeneity on trapping mechanism, fluid distribution and flow capacity. Examples discussed include (1) reservoir heterogeneity controlling fluid distribution and trapping mechanisms in two neighbouring gas fields, (2) geochemical evidence for a lateral seal separating gas condensate region from oil discovered during field development, (3) solid reservoir bitumen atop a giant gas field, (4) selective gas leakage through anhydrite seal, and (5) geochemical evidence for fault-controlled reservoir compartmentalization rather than a hydrodynamically tilted fluid contact in a field at an appraisal stage where PVT data are limited or inconclusive. Put in structural context, seal-related interpretations of the fluid data are aligned with observations from seismic and geological data on the existence of faults with favourable orientations or facies changes. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Integrated containment risks assessment for subsurface CO2 storage: Overburden analysis and top seal integrity study, offshore Norway

This study summarizes the OASIS (Overburden Analysis and Seal Integrity Study for CO2 Sequestration in the North Sea) project that focuses on assessing the containment risks associated with the geological carbon sequestration (CCS) of the Northern Lights project. CCS is viewed as one of the most effective solutions for reducing carbon emissions, as it captures carbon dioxide from point sources and permanently stores it in suitable geological formations. However, injecting CO2 into the subsurface may have mechanical consequences, including fault reactivation, top seal fracturing, surface heave, etc. This study proposes an interdisciplinary workflow to characterize the caprock, faults, and overburden associated with CCS projects in the Horda Platform area, to improve injection-induced containment risk assessment. Our findings show that the proposed workflows and tools effectively characterize stress-related mechanical hazards. However, due to the complex nature of rocks, it is challenging to evaluate the top seal integrity using a single method. Therefore, the proposed interdisciplinary approach is more effective for any fluid injection site's characterization, given the complex nature of the subsurface and its behavior under injection-induced stress changes. This research paper adds knowledge about the top seal integrity assessment and the reliability of injected CO2, making CCS projects more reliable and safer. Although this study focuses on the northern North Sea, the proposed methods are equally applicable globally to characterize subsurface CO2 storage sites. Apart from CCS projects, these research results can benefit other subsurface injection projects, such as water injection for reservoir management, wastewater injection for disposal, hydrogen storage, and hydraulic fracturing for unconventional hydrocarbon resources.

Assessing the impact of hydrodynamics on capillary seal capacity: application of the Manzocchi & Childs model in trap analysis workflows

The evaluation of seal in conventional stratigraphic and structural traps requires the characterization of the capillary top seal to assess the capacity to hold a hydrocarbon column. Typically, this seal analysis addresses the static seal and does not consider the role that hydrodynamics (the flow of water into or out of the reservoir) may play in influencing the seal capacity. Although possessing extremely low permeability, shale seals are not perfect seals and water can seep through them under an imposed hydraulic gradient. Likewise, water can move vertically through trapped hydrocarbon columns even though relative permeabilities are very low. The impact of this flow on the capillary seal capacity can, in theory, be quite profound and should be considered in seal analysis workflows. This paper revisits the Manzocchi & Childs model for hydrodynamic effects on capillary seals and employs it directly in real-world trap analysis. The implementation of this model is described, and a workflow developed to incorporate the impact of hydrodynamics into column height prediction. The technique is applied to several known over-pressured fields from the Norwegian continental shelf to evaluate its applicability. Preliminary results from Monte Carlo modelling are promising and with some agreement between the observed column heights and the predicted hydrodynamic seal-controlled columns, dependant on the parameterization used. Further testing is ongoing, but the methodology should be considered in exploration prospect evaluation. The impact of hydrodynamics on seal capacities should not be discounted. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Shale barrier performance in petroleum systems: implications for CO 2 storage and nuclear waste disposal

Shale is often required to act as a natural barrier to fluid flow around nuclear waste repositories and above CO 2 storage sites. The small pore size of the shale matrix makes it an effective barrier to fluid flow. However, leakage could occur along faults or fractures. Experiments provide insight into fault/fracture-related leakage on short timescales (i.e. 1–10 years) compared to that needed for safe disposal (up to 1 Ma). Data collected by the petroleum industry provides strong evidence on how faults and fractures in shale impact fluid flow on such timescales. Faulted shales act as seals to petroleum reservoirs and abnormal pressures on geological timescales (>10 Ma). This observation suggests that faults in shale can either form without acting as flow conduits or act as temporary conduits but then reseal. Index properties such as clay content and elastic moduli are useful for identifying shales in which faults/fractures are likely to self-seal. However, fault and fracture-related fluid flow can occur through weak shales if high overpressures are maintained. Nuclear waste repositories can be sited away from where overpressures could develop. Leakage from CO 2 storage sites is more risky because the CO 2 provides drive to maintain high pressures, which could suppress self-sealing. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Fault-seal analysis in the Greater Bay du Nord area, Flemish Pass Basin, offshore Newfoundland

A 3D subsurface structural model was built in a zone of the Greater Bay du Nord area, Flemish Pass Basin, offshore Newfoundland and Labrador, to carry out a post-drilled, fault-seal analysis in a multi-rift, geological complex setting; this aimed to test fault-seal predictions, calibrate computed static fault-zone attributes and estimate hydrocarbon contact depths. Hydrocarbon exploration campaigns in the Greater Bay du Nord area have primarily targeted rotated fault blocks that often exhibit structural segmentation and compartmentalization. A comprehensive approach that combines empirical and deterministic methods for static fault-seal analysis has been implemented. This approach provides insights into open, base and tight fault-seal scenarios, aiding prospect evaluation in this region. Notably, shale gouge ratios (SGRs) in the range 16–25% serve as a crucial indicator of the transition between fault-rock sealing and non-sealing fault segments. Furthermore, it emphasizes the critical role of hydrodynamics when calibrating or evaluating fault-sealing properties. In areas like the Greater Bay du Nord region, characterized by complex geology, it is imperative to regularly update fault-seal models. These updates should align with the availability of new subsurface data, comprehensive analyses and an improved understanding of the petroleum system. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

A new approach to investigate the effect of burial depth and clay content on fault permeabilities applied at the Njord Field

Fault permeability prediction typically relies on empirical relationships between permeability and clay content or burial depth. Calibration of such methods relies on either core data or subsurface observations of fluid pressure and hydrocarbon contact offsets across faults. Published core data suggest that no relationships exist between host rock clay content and fault permeability for phyllosilicate-framework fault rocks, whereas published subsurface calibration data suggest otherwise. We here present a new method for calibration of fault rock permeabilities to subsurface pressure data. This approach is an analogue from electrical engineering to compute fault permeabilities across all major faults in a study area and optimise depth and clay content dependence of fault permeabilities. We tested this method at the Jurassic section of the Norwegian Njord Field area, where faults span the depth range of 2.7- 4.5 km and the lowest clay content in individual faults varies between 8.9 to 25.7%. The flow-restricting faults at Njord are phyllosilicate-framework fault rocks. Our modelling shows that fault rock permeability decreases with burial depth, whereas the clay content has nearly no impact. Sensitivity analyses show that these results are robust. Therefore, SGR-based algorithms for fault seal prediction cannot be expected to give good fault permeability predictions for seismic-scale faults at Njord. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022 Supplementary material: https://doi.org/10.6084/m9.figshare.c.6824325

Old core, new tricks: a comparative study of old and new mudstone cores for applications in the energy transition

Repurposing depleted oil and gas reservoirs for secondary storage may play an important role in the transition to low-carbon energy. The integrity of the cap rocks overlying the reservoirs is an important factor for gas storage and needs to be understood prior to repurposing. In some cases, old cap-rock cores collected during exploration and development of oil and gas fields may be available for characterization using modern techniques but after being stored for decades these cores are likely to have experienced many changes in moisture, which can lead to physical changes. A comparative study of samples taken from old, unpreserved mudstone core and samples from a recently acquired and preserved core taken from the same formation shows that the mineralogy, porosity and permeability results are relatively similar between the two cores. The differences in the porosity measurements between the old and new core samples are primarily due to natural variations in grain size, rather than the preservation status of the cores. Geomechanical data, however, show significant and non-systematic differences between the old samples and the new samples, suggesting that old core samples are not suitable for geomechanical characterization. In the absence of new, well-preserved core, old core samples may provide suitable porosity, permeability and mineralogical data, whereas the old, unpreserved core is unlikely to provide reliable geomechanical data. Supplementary material: Individual BIB-SEM porosity measurements for each sample are available at https://doi.org/10.6084/m9.figshare.c.6725765 Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

A numerical model for gas CO 2 migration in a fault zone

Understanding whether fractures and faults impact the CO 2 migration through the overburden is critical in the evaluation and monitoring of CO 2 geological storage sites. We present a numerical model and workflow to describe the hydraulic behaviour of a fault located in the shallow part of the overburden. This helps to evaluate the sealing potential of the system in case of unwanted CO 2 migration toward the surface and to design an efficient monitoring plan. The model configuration is representative of several experiments performed at real sites under quite shallow conditions (50–500 m). The model results, applied to a selected fault outcropping in the Apennines (Italy), show that most of the gas migrates through the high permeable footwall damage zone. A significant amount of gas then dissolves into the water, emphasizing the importance of accurate modelling to assess the hazard of CO 2 leakage into near-surface aquifers or to the surface. The occurrence of pressure buildup close to the fault core points out that detailed modelling of the migration conditions is required to predict gas path through a fault zone. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: https://www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Regional mudstone compaction trends in the Vienna Basin: top seal assessment and implications for uplift history

Seal quality assessment is not only essential in petroleum systems studies but also in the context of other geo energy applications such as underground hydrogen storage. Capillary breakthrough pressure controls top seal capacity in the absence of faults or other discontinuities. In basins that lack measured capillary pressure data (e.g., from drill cores), regional compaction-porosity trends can be used as a first prediction tool to estimate the capillary properties of mudstones. Mathematical compaction models exist but need to be calibrated for each basin. This study aims to establish a compaction trend based on theoretical models, then compare it with theoretical maximum hydrocarbon column heights inferred from true measured capillary pressure curves. Middle to upper Miocene mudstone core samples from the Vienna Basin, covering a broad depth interval from 700 to 3400 m, were investigated by X-ray diffractometry, with an Eltra C/S analyzer, and by Rock–Eval pyrolysis for bulk mineralogy, total organic carbon, and free hydrocarbon contents. Broad ion beam—scanning electron microscopy, mercury intrusion capillary porosimetry, and helium pycnometry were applied to obtain pore structural properties to compare the mathematical compaction models with actual porosity data from the Vienna Basin. Clear decreasing porosity depth trends imply that mechanical compaction was rather uniform in the central Vienna Basin. Comparing the Vienna Basin trend to global mudstone compaction trends, regional uplift causing erosion of up to ~ 500 m upper Miocene strata is inferred. A trend of increasing Rock–Eval parameters S1 and production index [PI = S1/(S1 + S2)] with decreasing capillary sealing capacity of the investigated mudstones possibly indicates vertical hydrocarbon migration through the low-permeable mudstone horizons. This observation must be considered in future top-seal studies for secondary storage applications in the Vienna Basin.

Characterizing along- and across-fault fluid-flow properties for assessing flow rates and overburden fluid migration along faults: a case study from the North Sea

Assessing fault zones as fluid-migration pathways requires the characterization of permeability both across and along faults, as well as the adjacent volume. The hydraulic properties of the Vette Fault Zone, North Sea, are described by modelling the mixing of host-rock lithologies into the fault zone, and the fault width is derived from empirical relationships as a function of throw and clay content. To better understand the sensitivity related to the uncertainties in overburden lithologies and fault-width correlations, a parametric study with 1125 model realizations were solved in a 2D steady-state, single-phase, subsurface flow model. The fault zone, included as a discrete permeable structure, significantly alters the flow field compared to a model that only considers lithological juxtaposition. The most prominent hydraulic communication in the Vette Fault Zone is downwards from the storage reservoir where sand is mixed into the fault zone. Increasing the host-rock permeability in the overburden also increases the fault permeability and shifts the inflection point for down-fault flow, causing the pressurized reservoir to drain towards the overburden and the top surface. For CO 2 storage application, the models highlighted the potential for downward communication along the fault for brine, and the CO 2 capillary sealing towards the overburden. Thematic collection: This article is part of the Fault and top seals 2022 collection available at: www.lyellcollection.org/topic/collections/fault-and-top-seals-2022

Static Reservoir Simulations and Seismic Attributes Application to Image the Miocene Deep-Water Reservoirs in Southeast Asia

Globally, deep-water reservoir systems are comprised of a variety of traps. Lateral and downdip trapping features include sand pinch-outs, truncation against salt or shale diapirs, and monoclinal dip or faulting with any combination of trapping designs; the potential for massive hydrocarbon accumulations exists, representing significant exploration prospects across the planet. However, deep-water turbidites and submarine fans are two different types of traps, which are developed along the upslope and the basin floor fans. Among these two traps, the basin floor fans are the most prolific traps as they are not influenced by sea-level rise, which distorts the seismic signals, and hence provides ambiguous seismic signatures to predict them as hydrocarbon-bearing zones for future explorations. Therefore, the deep-water channel-levee sand systems and basin floor fans sandstone define economically viable stratigraphic plays. The subsurface variability is significant, and hence, characterizing the thick (porous) channelized-basin floor fans reservoir is a challenge for the exploitation of hydrocarbons. This study aims to develop seismic-based attributes and wedge modeling tools to accurately resolve and characterize the porous and gas-bearing reservoirs using high-resolution seismic-based profiles, in SW Pakistan. The reflection strength slices better delineate the geomorphology of sand-filled channelized-basin floor fans as compared to the instant frequency magnitudes. This stratigraphic prospect has an area of 1180 km2. The sweetness magnitudes predict the thickness of channelized-basin floor fans as 33 m, faults, and porous lithofacies that complete a vital petroleum system. The wedge modeling also acts as a direct hydrocarbon indicator (DHI) and, hence, should be incorporated into conventional stratigraphic exploration schemes for de-risking stratigraphic prospects. The wedge model resolves a 26-m thick hydrocarbon-bearing channelized-basin floor fans lens with a lateral distribution of ~64 km. Therefore, this wedge model provides ~75% correlation of the thickness of the LSL as measured by sweetness magnitudes. The thickness of shale that serves as the top seal is 930 m, the lateral mud-filled canyons are 1190 m, and the thick bottom seal is ~10 m, which provides evidence for the presence of a vibrant petroleum play. Hence, their reveals bright opportunities to exploit the economically vibrant stratigraphic scheme inside the OIB and other similar global depositional systems.

Selection of the Best Forecasting Method at PT. Indaco Warna Dunia

PT. Indaco Warna Dunia is a decorative paint company in Indonesia that produces products under the brands Envi, Belazo, and Top Seal. Preliminary observations revealed that the forecasting method used by the company is ineffective and inaccurate. This inaccurate forecast result company’s problem in fulfilling the demand. This study aims to select the best forecasting method to improve forecast effectiveness and accuracy. The research was conducted at the Tarakan depot, and the products understudy were a fast-moving product category, specifically the Envi brand. Several forecasting methods such as Moving Average, Weighted Moving Average, Single Exponential Smoothing, Exponential Smoothing with Trend, and Holt's Double Exponential Smoothing. The accuracy of forecasting is the most important and it can be measured with MAPE (Mean Absolute Percentage Error). The results showed that Holt's Double Exponential Smoothing method is the best for three products, while the Exponential Smoothing with Trend method, and Single Exponential Smoothing method are the best for one of the products, respectively.

Chapter 9. Application of sequence stratigraphy to the evaluation of selected North Sea Jurassic hydrocarbon fields and carbon capture, utilization and storage (CCUS) projects

Abstract The application of sequence stratigraphic concepts and methods augments the efficient development of North Sea hydrocarbon fields with Jurassic reservoirs. In particular, the approach provides enhancements to the development of robust reservoir zonations, more accurate assessments of the extent and continuity of reservoir zones and flow units, clearer identification and prediction of the most productive reservoir intervals, improved understanding of field-wide pressure barriers or baffles to fluid flow, and enhanced reservoir models. In addition, carbon capture and storage (CCS) projects in Jurassic rocks will benefit from the adoption of a sequence stratigraphic approach by enhancing the understanding of storage unit architecture, connectivity and top seals. In this chapter, these applications are discussed with reference to around 20 case studies from the North Sea Basin.

Carbonate sedimentation and reservoirs associated with a volcanic mound in an open-marine, deep-water, drowned platform setting, Elaine field area, Upper Cretaceous Anacacho Formation, South Texas U.S.A.

In the Upper Cretaceous Balcones Igneous Province in South and Central Texas, numerous small volcanoes developed during Austin Chalk and Anacacho deposition that are similar to the recent Surtsey volcano offshore of Iceland. The volcanoes formed topographic highs on the deep-water (500–900 ft [150–275 m]), earlier-drowned Comanche Platform. The Elaine field in South Texas is associated with one of these relict volcanic highs and integration of a 3D-seismic dataset and cores permitted a detailed analysis of the deeper-water carbonate depositional systems of the field and associated carbonate reservoir development. This reservoir description extends the understanding of petroleum systems associated with relict, open-marine, deep-water, volcanic highs. In the shallow water at the top of the volcanic topographic highs, a carbonate factory developed that produced coarser-grained carbonate sediments that sourced the deeper-water flanks and toe-of-slope of the mound. Finer-grained carbonate chalk was deposited in the open-marine, deep-water environment adjacent to the volcanic mound. The coarser-grained carbonate sediments sourced from the mound top were transported downslope by gravity-flow processes that formed debrites and hyperconcentrated density-flow deposits. The gravity-flow deposits are composed of a mixture of shallow- and open-marine, deep-water biota indicating they are not shallow-water deposits, but are deeper-water mound-flank and toe-of-slope deposits.In the Anacacho Elaine field, the coarser-grained carbonates (i.e., skeletal packstones and grainstones) associated with the volcanic mound are the oil-producing reservoirs. The Elaine volcanic mound itself is tight and not productive. The Anacacho chalk immediately above the mound are also tight and form the top seal for the Elaine field.Associated with the relict volcanic mounds in the Balcones Igneous Province are a spectrum of carbonate plays. The relict volcano can be a reservoir, but not all the relict volcanic mounds are porous. The coarser-grain carbonates on the top, flanks, and at the base of the volcanic mounds are reservoirs in the area of the Balcones Igneous Province. The chalks deposited penecontemporaneously on the open-marine, deep-water platform can also be tight carbonate reservoirs.

Influence of Top Seal Damage on Contact Seal in Ram Blowout Preventer.

Top seal failure of ram blowout preventer (BOP) is one of the main factors leading to well control risk. The constitutive model and parameters of nitrile butadiene rubber (NBR) were optimized by compression and tensile tests, and the failure analysis model of the contact seal of the ram BOP top seal was built. The nonlinear contact mechanical behavior of the connection part of the BOP top seal was analyzed by the finite element method. Then, the influence of corrosion and wear defects at the top seal position of the 2FZ35-70 BOP under rated working pressure on the contact seal were studied, and the results showed that the overall contact pressure distribution of the top seal corrosion defects was uniform, the local contact pressure of the corrosion pit edge increased, and the top contact pressure decreased. The overall contact pressure of the wear defect of the top seal decreased linearly, the contact pressure at the maximum depth of the wear defect was the smallest, and the contact pressure gradually decreased to both sides. Ultimately, to guarantee the safety and reliability of the ram BOP, it is suggested that the acceptable depths of the seal corrosion pit and the wear at the top of the ram BOP are 4.0 mm and 0.2 mm, respectively, thus the reliability evaluation problem of the quantitative seal of the ram BOP top seal is solved.

Thermal maturity modelling for the source rocks in blocks 10 and 11.1, Nam Con Son basin

Blocks 10 and 11.1 are located at the western boundary of the Nam Con Son basin, offshore southern Vietnam. Hydrocarbon shows have been encountered in many wells as the Gau Chua (GC), Ca Cho (CC), Gau Ngua (GN), Phi Ma (PM), Than Ma (TM), etc. In the CC and GN fields, the oil and gas were discovered in Miocene sandstone reservoirs and in fractured granite basement. The Cau and Dua formations are active source rocks in this area. Oil and gas discovered in wells were generated from coal and coaly claystone sediments which deposited under oxidation conditions to weak reducing in fluvio-delta to estuarine environments, in which land plants develop very abundantly. The 2D modeling results suggested that hydrocarbons discovered in the study area mainly derived from the local source rocks. The large quantity of hydrocarbons yields from source rocks in deeper part of southeastern kitchen migrated both vertically and laterally into the overlaying formations. Hydrocarbon strongly migrated lost through open fault. Prospects located near kitchen can trap hydrocarbons if they have a good seal. Block 10 and western block 11.1 face high risk of hydrocarbon charge due to the distance from the kitchen, weak top seal and fault seal. Of seal scenario, the composition of hydrocarbons accumulated in GC structure contains 87.5% volume of liquid and 12.5% volume of gas that derived from local Oligocene source rock. The composition of hydrocarbons in accumulation in CT (Ca Ty) structure of contains 99% volume of liquid and 92.5% volume of gas that derived from local Oligocene source rock.