Reservoir prediction is a core area of research in oilfield exploration and development, and it is generally constructed on a combination of well data, seismic attributes or inversion. However, reservoir prediction in sparse well areas poses great challenges due to insufficient well control. If the quality of seismic data is poor, the spatial distribution characteristics of reservoirs cannot be effectively characterized through inversion or attribute analysis, which seriously affects the prediction accuracy. This paper proposes a new method to solve the difficulty in reservoir prediction of oilfields with sparse data and poor quality seismic cube, which evolves from depositional models, forward stratigraphic modeling (FSM) to geocellular modeling. First, based on the comprehensive analysis of core, seismic, grain size, heavy minerals, dip data, it is believed that a special fan delta developed in the Miocene strata in the south of Albert Basin. The reservoirs are dominated by distributary channels, which are in medium-coarse grains, and the provenance is from the southwest to flowing to the northeast. The formation thickness of the stratum decreases from the boundary fault to the direction of the basin. Then, the input parameters of FSM modeling are quantitatively expressed based on the sedimentary model research, including model boundary conditions, basic input information, sediment supply and transportation. FSM results were used to quantitatively characterize the deposition process. The FSM simulation results are compared with the depositional model and well data to verify the reliability. Finally, the shale content model in FSM results is resampled to the geocellular grids and used as the constraint for facies model and property model in geological modeling. This model is used for well pattern design and optimization. This new approach integrates the conceptual depositional model with quantitative FSM results. It improves the accuracy of reservoir prediction and provides a new technical workflow for reservoir characterization. Furthermore, it helps to obtain more insight into the sedimentary process and reduces the risk of oilfield exploration and development.

Salt is known for having a generally low density and higher velocity compared with the surrounding rock layers which causes the energy to scatter once the seismic wavefield hits the salt body and relatively less energy is transmitted through the salt to the deeper subsurface. As a result, most of imaging approaches are unable to image the base of the salt and the reservoir below the salt. Even the velocity model building such as FWI often fails to illuminate the deeper parts of salt area. In this paper, we show that Full Wavefield Redatuming (FWR) is used to retrieved and enhance the seismic data below the salt area, leading to a better seismic image quality and allowing us to focus on updating the velocity in target area below the salt. However, this redatuming approach requires a good overburden velocity model to retrieved good redatumed data. Thus, by using synthetic SEAM model, our objective is to study on the accuracy of the overburden velocity model required for imaging beneath complex overburden. The results show that the kinematic components of wave propagation are preserved through redatuming even with heavily smoothed overburden velocity model.

A 3D surface seismic data acquisition project was conducted simultaneously with 3D DAS-VSP data acquisition in one well in Jilin Oilfield of Northen China. The 3D surface seismic data acquisition project covered an area of 75 km 2 , and one borehole (DS32-3) and an armoured optical cable with high temperature single mode fiber were used to acquire the 3D DAS-VSP data simultaneously when the crew was acquiring the 3D surface seismic data. The simultaneously acquired 3D DAS-VSP data were used to extract formation velocity, deconvolution operator, absorption, attenuation (Q value), anisotropy parameters ( η, δ , ε ) as wel as enhanced the surface seismic data processing including velocity model calibration and modification, static correction, deconvolution, demultiple processing, high frequency restoration, anisotropic migration, and Q-compensation or Q-migration. In this project, anisotropic migration, Q-migration was conducted with the anisotropy parameters ( η, δ , ε ) data volume and enhanced Q-field data volume obtained from the joint inversion of both the near surface 3D Q-field data volume from uphole data and the mid-deep layer Q-field data volume from all available VSP data in the 3D surface seismic surveey area. The anosotropic migration and Q-migration results show much sharper and focussed faults and and clearer subsutface structure.

The genetic mechanism of shallow gas reservoirs is complex, which is usually characterized by shallow burial depth, multiple types, low reserves and wide distribution, so that the inversion based on P-wave data alone may be ambiguous. For shallow reservoir with large lateral variation, it is hard to accurately predict oil and water distribution by conventional P-wave prestack inversion. Marine four-component (M4C) P-wave and S-wave joint inversion can solve the problem effectively. M4C seismic survey collects P-wave and S-wave seismic data. An initial model can be established based on fine structural interpretation of P-wave and S-wave data and S-wave compression pattern matching. It lays a good foundation for subsequent P-wave and S-wave joint inversion. Based on the P-wave seismic record equation proposed by Fatti et al., a seismic record equation from poststack P-wave and S-wave joint inversion was derived according to the relationship among reflection coefficient, P-wave impedance, S-wave impedance and density, then important lithologic parameters (P-wave impedance, S-wave impedance and density) were calculated, and finally the ratio of P-wave velocity to S-wave velocity which is more sensitive to oil and gas was obtained. According to the ratio of P-wave velocity to S-wave velocity, the oil and gas distribution was predicted in shallow Bohai Bay Basin. Application has proven that the inversion can well reflect the fluid distribution, and the coincidence between the inversion results and the drilling data is up to 85%.M4C seismic survey was conducted for the first time to the shallow oil and gas reservoirs with rapid lateral variation in the Bohai Bay Basin, and collected raw P-wave and S-wave seismic data. Based on the data, the precision and reliability of P-wave and S-wave joint inversion was improved. The results provided strong technical support to the reserves and production increase in the Bohai Bay Basin.

The space of fracture reservoir in granite buried hills varies sharply with strong heterogeneity and very difficult to predict. Conventional fracture prediction methods based on narrow-azimuth post-stack seismic data have low prediction accuracy. OVT pre-stack gather retains the information of offset and azimuth, reflects the anisotropic characteristics of fractures and can be effectively used to predict the strength and strike of fracture in granite buried hills. In this paper, based on the analysis of anisotropy of OVT gather data, according to the geological characteristics of granite fractures, optimizes the sensitive offset and azimuth OVT gather data, uses the P-wave azimuth anisotropy technique to predict the strength and strike of fractures. The prediction coincides well with the drilling results, which can provide an important guidance for the exploration and development of granite buried hill in the research area.

The biogas lithologic reservoirs in Sanhu Area of the Qaidam Basin has a broad exploration prospect, however, the demands of structural implementation and reservoir prediction can hardly be met with the existing P-wave seismic data due to the thin thickness of single sandstone layers, the rapid lateral changes and the low prediction accuracy of lithologic reservoirs. The SH-wave data has a higher resolution ability in lithology prediction. I can better reflect the lateral change features of formations. Because few SH-wave logging data are available and they are in accurate in the current study area, the SH-wave velocity is estimated through petrophysical modeling and the calibration and horizon interpretation of the SH-wave data are realized combined with the P- and SH-wave matching technology. Through the inversion of S-wave data,the lithological distribution of formations are predicted in combination with the comrehensive analysis of P-wave data, which provides a favorable basis for the survey of lithologic gas reservoir in the research area and achieves a good good result. In this way,a set of reservoir prediction methods and processes suitable for the shallow biogas lithological exploration in the Sanhu Area have formed initially.

The pore pressure profile of an exploration well in high pressure and high temperature (HPHT) A-Field of Nam Con Son Basin was initially predicted along the wellpath in tandem with the analogy to an offset well to design a drilling program of penetrating the unreachable sedimentary formation. The scheme had driven mud weight to encounter the pressure ramp but resulted in underbalance and influx into the wellbore that incurred downtime for well control. Subsequently, formation pressure measurement conceded the substantial disparity over the offset well so the post-drill study was conducted towards with 3D geological modeling and fault seal analysis to gain insight into overpressure generation mechanisms of the field. Seismic interval velocity, density, resistivity data are applied for generating the validated pore pressure profile of exploration well on both Eaton and Bowers methods with calibration on formation pressure measurement for Middle and Lower Miocene Sequences. Besides, the cutting edge 3D modeling is approached to construct a robust structural and fault framework as well as to condition and upscale ultimate shale volume, pressure gradient, and overburden stress for facies and pressure distribution. The sealing capacity of a fault is quantified in terms of the pressure acting on the fault surface that is required to be exceeded for the fault to become unstable and slip including simulations of formation juxtaposition mapping, fault clay content prediction, fault flow indicators, and transmissibility. Upon completion of the 3D model, the fault surfaces which are mapped by shale volume could provide a detailed geometry and lithology juxtaposition analysis for the fault planes. The results of the high Shale Gouge Ratio (SGR), very low fault permeability, and relatively high fault rock thickness imply that the studied faults act as a baffle to fluid flow. However, from juxtaposition observation, the displacement broadens with depth in some parts of faults and the lateral stress increases through the sync-rift stage of Middle Miocene could be a cause of overpressure in this studied area. The 3D pore pressure and stress regime integrated with fault seal analysis in the model are generally obtained to provide both vertical and spatial overpressure characterization and advantages for well drilling plan and reservoir production. From the drilling aspect, a fault stability study can optimize the maximum allowable mud weight to not exceed while drilling so that fault reactivation does not take place. From a depletion perspective, understanding of stress variations due to lowering reservoir pressure with time can be incorporated with fault seal analysis.

One of the major brownfields in offshore India was producing for three decades from main carbonate reservoirs of the Eocene and Oligocene age. Average production of this brownfield is approximately 11,000 barrels of oil per day (BOPD). To maintain the declining reservoir pressure, the field has been under active water injection for more than two decades. However, being a complex carbonate reservoir with high textural heterogeneity, the water-front movement is not very well understood and monitored. To increase the oil production, the operator started drilling horizontal drain-holes from the platforms and has adopted a conventional perforated and blind tubing combination as a completion strategy. However, it was found that wells were performing poorly with very high water cut. An integrated and comprehensive petrophysical workflow was applied that used data analysis and the added value of advanced 3D acoustic data in combination with nuclear magnetic resonance (NMR) data to provide a rapid realistic solution to avoid such high watercut through optimizing the completion strategy. This led to a production gain in this offshore field, which was underperforming as per earlier predictions and expectations. Conventional well-log based qualitative evaluation for horizontal segmentation strategy was rejected in favor of an integrated approach for lateral reservoir facies delineation. Lateral petrophysical property characterization was carried out through quick integration of NMR pore-size driven facies analysis, advanced acoustic radial profiling, anisotropy, and Stoneley analysis. Permeability profiling along the horizontal drain-hole section using NMR and acoustics provided critical insight. Those were integrated to avoid potential high permeability conduits of thief zones for water breakthrough. A rock-quality index was derived to optimize the completion strategy soon after the logging, even preceding the rig-down of the acquisition runs and lowering of the completion. Zones with higher skin, deeper formation damage, and lower rock-mechanical properties were avoided for efficient swell-packer placements. The well started producing and continued production with only 10% water cut along with 450 barrels of oil compared to an average 90% watercut and 100 barrels of oil from the other wells of the same platform, which used the older nonoptimized completion strategy. Based on the promising result for the first well, the same workflow was used for two similar wells of other two different platforms inthe same field, which also resulted in similar production with enhanced oil production and reduced water cut. The study using the rapid integrated evaluation workflow established efficient zonal isolation of high permeability thief zones with accuracy for timely optimization of horizontal well segmentation, which assisted in pulling higher production in this brownfield by reducing unwanted water production.

Abundant faults, long oil-bearing intervals (up to 500m), and diverse fluids including conventional oil and heavy oil, result in P oilfield became one of the most complex oil fields in the Bohai Bay. The main characters ofinitial development plan are directional well with commingle production, open hole completion, large draw down, high oil production rate, and reverse nine-point well pattern. At present, the oilfield has entered a stage of high water cut, with average water cut more than 85%. What can we do next, decommissioning or rebirthing? An integrated solution was proposed to redevelop the oilfield which focus on the layers’ subdivision, the fine description of the sand body,a large number of horizontal wells on the top of the water-flooded layer are used to tap the potential, increase the water injector to transform the stream lines and rebuild the reservoir pressure, and search for potential sand bodies to increase reserves.

Demonstrating a viable development for the Ekofisk reservoir directly above the producing Tor reservoir in the Halfdan Field (Danish North Sea) has historically been challenging. A recent well shows the value of cross-disciplinary collaboration and new technology to maximize recovery and mitigate reservoir and drilling risks. Specifically, 4D seismic was utilized when planning the well, while placement was optimized by using advanced geosteering tools. Well optimization was further enhanced by adopting novel completion and stimulation technologies. Pressure data and 4D seismic show that Tor and Ekofisk are in dynamic communication, but the degree of communication varies locally. The integration of 4D seismic with other disciplines’ input succeeded in optimizing the well placement and narrowed the significant pore pressure uncertainty along the 12,000-ft reservoir section. To maximize well length within the target zone and reduce the risk of being faulted out of the target reservoir deep resistivity was used to steer the well in the optimal layers. This contributed to 99% of the reservoir section being placed in the target zone. Lessons learnt from an earlier appraisal well and modest production experience in this part of the Ekofisk reservoir helped to justify the choice of selective completion zones (Sliding Side Door) in the inner part of the horizontal drain in order to minimize the impact of potential water or premature water breakthrough from high-rate injection wells located in the underlying Tor reservoir. This decision was validated after drilling the inner part of the well, where water-swept zones were encountered in the heel, followed by a long gas pay zone in line with 4D seismic signal in the remainder of the inner well section. To mitigate the risk of an unwanted fracture connection and increase contact with the tight oil-saturated reservoir, a novel stimulation and completion technology was successfully deployed in the outer 6-inch open-hole section of the well. The acid needles completion, deployed across a 3,000-ft reservoir interval and comprising 224 needles deployed by pumping acid, was the first installation of its kind in the Danish North Sea. For the acid needles completion, this installation holds two distinctions: the largest number of acid needles installed in a well, and the combination of the acid needles completion with a different completion system in a single lateral for the first time.

The Yingxionglin structural belt located in the world's highest-altitude petroliferous basin, Qaidam Basin. Due to its complex surface condition, subsurface structure and low signal-to-noise ratios (SNR) of seismic data, exploration and production is quite challenging. From 2012 to now, we continued developing and improving seismic data processing and interpretation workflow. After several rounds field support and testing, new techniques exploring and velocity modelling iteration, we gradually developed a suitable workflow for complex dipping structure imaging including signal processing, velocity modeling, and depth migration. The quality of final delivered 3D seismic data is significantly improved with the integrated static correction techniques, fidelity multi-domain noise attenuation, 5D MPFI regularization, integrated velocity modelling and final pre-stack depth migration. According to our final deliverables, we identified credible traps and high-production reservoirs were found.

This paper showcases the tailored initiatives undertaken in a different economic climate in view of low oil price in maturing and capturing potential development opportunities for a large-sized, brownfield asset. The subject field is mature, having over 250 wells with over 20 years of production history and approaching its end of economic life. The study emphasized pursuit of a fast and cost-effective approach in identification of several potential behind-casing recompletion opportunities in addition to multiple infill drilling opportunities. From well log observation to seismic interpretation, and from material balance to simulation modeling, the approaches utilized were tailored based on the level of reservoir complexities. Lower cost, lower risk, behind pipe opportunities had previously not been a focus or thoroughly assessed since the company had focused on infill drilling opportunities. A robust execution plan, minimizing rig moves, was also prepared to synergize the ongoing and planned infill drilling campaigns in the field. An infill drilling well proposal was approved as part of the 2014 Field Development Plan (FDP) update with regulators. This plan was subsequently deferred due to drop in oil price resulting lower economics. However, with the field approaching the end of its economic producing life, a revisit of potential opportunities was conducted by a multi-disciplinary team. Results of the more recent opportunities identification and successful drilling campaigns have revived the proposal for the infill well given the synergies with rig utilization. The team went through a simplified governance process on the FDP, revisiting the simulation model and proposed to drill a horizontal infill production well instead of dual-string deviated well (originally envisioned for long string as an infill producer in the target reservoir and short string completed as a water injector in a different reservoir). Due to further well performance analysis, injection support on the other reservoir was no longer deemed necessary. The team analysis for arriving at this optimization as well as the behind-casing recompletion opportunities will be shared in this paper. This is a case study on how assimilated and innovative approaches undertaken in a different economic climate can be crucial to accelerate a brownfield re-development to extend the economic life of a mature producing field. A multi-disciplinary team applied creative thinking and cooperative efforts to a mature field to revive economic viability. Revisiting previously identified opportunities in the context of a low oil price environment and a simplified regulatory governance process, cross functional and cooperative technical and financial team work were important in facilitating timely decisions needed to move forward. A similar approach will be undertaken for future work in other fields.

The North West Shelf of Australia contains a late Paleozoic to Cenozoic sedimentary succession, which attains a thickness of over 10 km and is dominated by Triassic to Lower Cretaceous sediments. The deeper plays exist at multiple stratigraphic levels including oil-prone Jurassic sediments and faulted gas-prone Triassic sediments. The area has been proven difficult as far as seismic imaging is concerned, particularly over the Madeline trend. The presence of a hard, rugose water bottom, strong reflectors beneath the water bottom, and shallow Tertiary carbonates make the Dampier Sub-basin vulnerable to multiple contamination, amplitude distortion, lower signal-to-noise ratio (S/N) and unreliable AVO response. Poor seismic quality in the data has been a significant barrier to reducing exploration risk. In the 1990s, East Dampier (1992, blue polygon in Figure 1 ) and Keast (1997, yellow polygon in Figure 1 ) seismic data were acquired in East-West and North-South directions respectively, in an effort to better understand the impact from the shallow complex overburden. To address these challenges, the Demeter survey was acquired in 2003 (black polygon in Figure 1 ) with a denser acquisition grid. The overall seismic quality was improved, but the results still contained a significant level of residual multiples. Later, the Fortuna survey, the most comprehensive multi-sensor seismic survey on the North West Shelf of Australia to date, was acquired in 2014 with the aim to provide better subsurface imaging (pink polygon in Figure 1 ) from different acquisition perspectives. The data was processed with advanced processing technology, including shallow water demultiple, deghosting and high definition tilted orthorhombic velocity model building ( Birdus et al., 2017 ). However, the final results were still suffering from a number of challenges, specifically: 1) strong residual multiple in near offsets, 2) low S/N ratio, particularly at reservoir level, and 3) inconsistency from near to far stack resulting in unreliable AVO. In this paper, the Dixon area (green polygon), considered as the most challenging area in the Dampier Sub-basin, was chosen as the testing area for our work. By integrating high-end imaging technology, for example dual-sensor deghosting, multi-survey surface related multiple elimination (MAZ-SRME), and multi-azimuth processing (MAZ stack), we will illustrate how we have overcome many of these imaging challenges.

Major reservoirs in Field A namely A-2, A-3U, A-3M, and A-3L, are deposited within a multi stacked channel complex system within Group I in Malay Basin. These reservoirs were previously understood based on existing data to have no or very minimal vertical communication between them and are treated as separate systems. In 2018, three wells were proposed to drain the attic oil in the north region of A-3U reservoir. When drilling these infill wells, it was discovered that the pressure has exceeded initial reservoir pressure although the reservoir has been idle for almost a year prior to the drilling. The results of the multi-rate test of two of the three infill wells that are less than 1 km apart are significantly different from one another. Post drilling, more tests were executed to investigate the connection between the sand. Studies were also done by incorporating the static and dynamic reservoir modeling data. Based on the result of the tests and studies, it was concluded that all of the major sands are connected at some areas. This new finding on the connectivity might be able to explain the additional volume needed to history match some of the reservoirs. Establishing stratigraphy concepts of a reservoir particularly in a channel complex system is an ongoing process, in this case, a brown field of almost 20 years of production. All data including new well data and dynamic data plays a vital role for a better understanding of the reservoir. It is essential to incorporate the updated geological understanding into the static model to have a representative simulation for better history matching and prediction. Moving forward, instead of building a separate grid model for each reservoir, a larger framework consist of intercalated reservoir grids will be built with this new geological understanding for dynamic simulation.

G oilfield in China is a dual medium oilfield dominated by carbonate reservoir, where faults and fractures are well developed. After G oilfield was put into production, water cut has rised quickly and oil production decreased rapidly. The heterogeneity of fracture development is very strong. Because of unclear understanding of the fracture distribution, oilfield development plan can not accurately identify risks and potentials accurately. As a result, production goals are not as expected. Due to limited core data and imaging logging data, conventional methods cannot characterize fracture information in this oilfield accurately and comprehensively. In order to solve the problems mentioned above, this paper makes full use of logging, geology, seismic and other data to carry out fine characterization of fracture with multi-information fusion fracture modeling based on neural network. Firstly, neural network technology is used to predict the fracture density curves of wells with conventional logging data. Secondly, combined the nonlinear fusion of multiple pre-stack seismic attributes including Tectonic Stress Field, P-Wave AVO and Seismic Discontinuity Detection based on neural network, the fracture density probability model is created to predict three-dimensional distribution of fractures. Thirdly, the fracture Intensity model is set up under the constraint of strict variation function analysis and fracture density probability model. Finally, fracture parameters are obtained according to core observation and imaging logging data, and the fracture network is established by geostatistics modeling method and coarsened equivalent into fracture property model. Blind well validation and dynamic validation are used to verify the validity of fracture model. Under the guidance of research results in this paper, the oilfield development plan is optimized and adjusted. It has also been proved that fracture characteristic of new wells is consistent with pre-drilling prediction result. Most areas with relatively high fracture development degree are corresponding to well groups with faster water cut rising rate. Against the backdrop of global oil economic downturn, fracture modeling technology studied in this paper provides strong technical guidance for oilfield development plan, therefore reducing oilfield development risks and maximizing economic benefits.

Sonic data are commonly acquired in exploration, appraisal, and development wells using wireline, logging-while-drilling, or through-the-bit conveyance for applications within petrophysics, geophysics, geomechanics, and geology disciplines. The measurement data require processing to obtain elastic wave slownesses (inverse of velocity) and associated attributes before the results can be used in petrotechnical workflows. The objective of the digital transformation is to streamline and automate the processing workflow to reduce user intervention and turnaround time while increasing the accuracy of results and possibly extracting more answers by fully utilizing all waveform attributes, which consequently benefits downstream applications. There are four workflows that are the foundation of the transformation. They support the overall goals of reducing user interactions and providing robust results in a timely manner for continuous slowness logs. First, data-driven inversions done during acquisition with automatic quality control and interpretation flags immediately provide assurance about the data quality and identify formation intervals that require further evaluation. Second, automatic dipole-flexural shear extraction is done using physics-based machine learning (ML) where purely data-driven models are inadequate due to borehole or geological conditions. The physics-based ML utilizes cloud-based computing that is needed for large volume synthetic data generation and neural network training. Third, a multiresolution analysis of the monopole waves for the compressional slowness uses automatic peak detection on multiple receiver levels removing any subjective manual labeling after the semblance processing. Finally, the multimode (flexural and Stoneley) inversion determines anisotropic constants and accounts for mud-speed variations in the borehole, including detailed uncertainties. The new methods address underlying concerns most users and waveform processing experts already observe in their sonic deliverables. Enabling wellsite algorithms to be more automatic and data driven improves the robustness of the field deliverables and provides insight into the quality of the data. For the shortcomings with regards to borehole or geological conditions such as laminations, sharp lithological transitions, or the presence of anisotropy, the physics-based ML is shown to honor the physics of the dipole flexural mode, while the multiresolution for the monopole provides physics-based reasoning for discrepancies between the geological layering and receiver aperture. By incorporating the range of results derived from the inversions with advanced interpretations such as transversely isotropic constants, these uncertainties can be further used in stochastic models in downstream workflows. All these methods are fully automated and can be done in a short timeframe to be used without doubt in operations.

JZ Gasfield is an offshore sublacustrine fan lithologic gas field located in Bohai Bay Basin, in China, with a buried depth of about 1750m. It is currently in the stage of overall development plan preparation. Two exploration wells have been drilled. They show that the gas field has characteristics of rapid lateral change in reservoir, complex distribution range and connectivity of sand bodies. In addition, the few drilling data, large well spacing and low resolution of seismic data in the evaluation stage make it extremely challenging to establish an accurate geological model of gas reservoir. In order to solve the above problems, in this paper, an integrated geological modeling method based on seismic frequency division processing and fluid substitution forward modeling is proposed. There are four key aspects to this method. (1) Using seismic sedimentology, the lateral distribution ranges of sublacustrine fan sand bodies are described by seismic frequency division processing and interpretation technique and seismic variance attribute. (2) Based on markers of single-well, logging and seismic faceis, the average instantaneous frequency attribute is selected by optimizing the seismic attributes in the dominant frequency band, and then the distribution ranges of three subfacies including inner fan, middle fan and outer fan of the sublacustrine fan are characterized, and the fine sedimentary pattern of the sublacustrine fan is established. (3) Based on an understanding of the sedimentary pattern, fluid substitution forward modeling is carried out, and the superposition and connectivity of the sublacustrine fan sand body are described. (4) A 3D geological model of the sublacustrine fan sand body is established by using a new four-step modeling method including the concept of facies-in-facies modeling: 1) A model of the distribution of the sand body is established through a deterministic modeling method; 2) Within the sand body, according to the division results of subfacies, the distribution model of sub-facies is established; 3) A fine lithofacies model is established by combining stochastic simulation with deterministic modeling and hierarchical modeling from rough to fine under the constraint of a seismic attribute; 4) Petrophysical models are established by lithofacies control, which provide a more accurate geological model for preparation of the gas field development plan. Based on this comprehensive study, it is concluded that there is a great possibility of reservoir disconnection between the inner fan and the middle fan, where the gas reservoir is located, and the inner fan in the updip position of the structure has the risk of no gas accumulation, and the drilling risk in the development stage is greater than the potential. Based on this geological understanding, the available reserves of the gas field are reduced by nearly 40%.

OBJECTIVE / SCOPE The Black Sea is a Mesozoic-Cenozoic closed sea system representing one of the last few exploration frontiers in the vicinity of the European market. The overall prospectivity of the basin and associated regional prospective trends have been delineated using the integrated Play-Based Exploration approach. The tectonic evolution, basin formation, sedimentary infilling history, petroleum systems, and sedimentary plays have been investigated to search for new hydrocarbon potential in the basin. METHODS, PROCEDURES, PROCESS The seismic interpretation and mapping were based on 26 sparse 2D seismic lines (ION SPAN), which were acquired and processed in 2011-2012 by ION GTX. The multi-client data from offshore Russia, Crimea, and Ukraine were excluded due to geopolitical sanction. The seismic interpretation which was completed in the depth domain (PSDM depth) was calibrated using three Deep Sea Drilling Project (DSDP) wells namely Sites 379, 380, and 381 ( Fig. 1 ) which penetrated only the shallower section namely the Top Miocene and Top Pliocene. However, the seismic markers where lacking well penetration were primarily interpreted based on seismic stratigraphy. Interpretation of the acoustic basement as well as crustal types were supplemented with gravity and magnetic data from Getech Globe’s database. Three key seismic lines ( Fig. 1 ) were then selected to illustrate the overall basin geomorphology, structural evolution, and to subsequently identify play potential within the basins. The structural analysis was integrated with the seismic sequence stratigraphic analysis to understand the sedimentation history, depositional trends, kinematic evolution, and tectonic history.

The increasing atmospheric concentration of carbon dioxide (CO 2 ), a greenhouse gas (GHG) is creating environmental imbalance and affecting the climate adversely due to growing industrialization. Global leaders are emphasizing on controlling the production of GHG. However, growing demands of natural gas, industry is embarking on the development of high CO 2 contaminant gas fields to meet supply gap. Development and management of contaminated hydrocarbon gas fields add additional dimension of sequestration of CO 2 after production and separation in project management. CO 2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, measuring and verification (MMV) of injected CO 2 volume in sequestration is critical component along with geological site selection, transportation, storage process. The present study discusses all the impacting parameters which makes whole process environment friendly, economically prudent and adhering to national and international regulations. The migration of injected CO 2 plume in the reservoir is uncertain and its monitoring is equally challenging. The role of MMV planning is critical in development of high CO 2 contaminant fields of offshore Sarawak. It substantiates that injected CO 2 in the reservoir is intact and safely stored for hundreds of years after injection and possesses minimum to no risk to HS&E. The deployment of Multi-Fiber Optic Sensor System (M-FOSS) promises a cost-effective solution for monitoring the lateral & vertical migration of CO 2 plume by acquiring 4D DAS-VSP (Distributed Acoustic Sensor – Vertical Seismic Profile) survey and for the well integrity by analyzing DAS/DTS (Distributed Temperature Sensor)/DPS (Distributed Pressure Sensor)/DSS (Distributed Strain Sensor) data. Simulation results and injectivity test at laboratory for in-situ CO 2 injection has demonstrated the possibility of over 100MMscfd/well injection in aquifer to meet the total CO 2 injection of 1.2Bscfd for full field development while maintaining the reservoir integrity. Uncertainty & risk analysis shows possible presence of seismically undistinguished fractures and minor faults, an early breakthrough of injected CO 2 cannot be ruled out. The depleted reservoir storage study divulges the containment capacity of identified carbonate reservoirs as well as conformance of potential storage sites. The fault-seal analysis and reservoir integrity studies determine the robustness of the long-term security of the CO 2 storage. Injectivity study demonstrates the optimum and maximum possible rates of CO 2 injection into these depleted gas reservoirs. VSP simulation results show that a subsurface coverage of 3-4 km 2 per well is achievable, which along with simulated CO 2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. The deployment of M-FOSS technology is novel and proactive approach to monitor the CO 2 plume migration and well integrity. First ever development of MMV Planning for CO 2 Sequestration in offshore Sarawak, Malaysia using novel and cutting-edge M-FOSS technology for proactive monitoring of CO 2 plume migration and well integrity.

The performance of pre-stack depth migration (PSDM) on the fiber optic, distributed acoustic sensing (DAS), vertical seismic profile (VSP) data has rarely been reported. We show the results of PSDM for the fiber optic cables, newly developed and tested at a field in Canada. We apply Kirchhoff migration, Fresnel volume migration and reverse time migration (RTM) to the walkway VSP data to obtain high resolution images of the shallow to deeper structures and provide the performance analysis of the migration methods for the DAS VSP data.