This paper demonstrates how an operator mitigated a hazardous pore pressure drilling risk using a technology that was new to the operator. The Seismic While Drilling (SWD) increased safety and efficiency at lower cost over commonly used alternatives. In 2019 MOL Norge AS drilled a deviated exploration well in the southern part of the Norwegian North Sea. The large 300 bar pore pressure uncertainty in the reservoir made it necessary to land the 9 7/8-in casing shoe as close as possible to the reservoir to maintain a safe kick tolerance. The pre-drill depth uncertainty of +/- 75m at the reservoir made it necessary to find a reliable technology to significantly decrease this depth uncertainty. Borehole seismic technology enables measurement of seismic velocities, which is the main culprit in seismic depth uncertainty. Measuring the time taken for a seismic pulse from a surface airgun to reach a downhole sensor provides velocity information which can provide a significant reduction in depth uncertainty while drilling. The closer the seismic sensor is to the formation of interest then the more accurate the depth prediction of the formation top is. In addition, seismic reflections from the formation top can provide a lookahead capability extending to hundreds of meters. SWD technology coupled with 3D ray-trace modelling allowed a survey to be designed for this deviated well using rig deployed airguns rather than deployment from a costly additional vessel. The survey design included real time data during drilling to significantly reduce the depth uncertainty and also image the reservoir top. The 12.25in hole section was drilled with a seismic logging while drilling (LWD) tool in the BHA, acquiring data during the drilling connections. Vertical Seismic Profile (VSP) processing of the real time data allowed the drilling team to see seismic reflections from the reservoir top during the approach from over 600m away. The decision to stop drilling occurred when the lookahead image indicated the reservoir was at a depth of 3,426 m TVD (+/- 13m), 50m shallower than the predrill plan. The casing point was set at a depth of 3,402 m TVD, approximately twice the depth uncertainty above the lookahead prediction. The actual reservoir top was subsequently logged at 3,425.6m TVD, less than 1m from the predicted depth.

Innovations in the field of fiber optics have resulted in the application of distributed acoustic sensing (DAS) for borehole seismic applications. A hybrid optical-electrical cable has been developed to enable conveying all logging suites required during the entire well construction. From intermediate drilling section evaluations through well integrity and production, the optical fiber enables seismic acquisition during any wireline intervention. Because the optical fiber inside the logging cable is the seismic sensing element, velocity information can be measured along the entire wellbore very efficiently. The acquisition of a borehole seismic program, such as a zero-offset vertical seismic profile (VSP) is reduced to minutes, instead of hours or days. Also, no additional rig time is needed if the seismic information is acquired during logging runs that involve remaining stationary in the borehole, such as fluid sampling and calibration of nuclear magnetic tools. Improvements in drilling efficiency from using this technology are achieved in several ways: 1) elimination of a dedicated seismic run, which renders substantial rig time savings; 2) lowering risk of operations (i.e., avoiding fishing); 3) virtual elimination of nonproductive time due to downhole tool failure and the provision of many opportunities to gather data (logging runs in open or cased hole); 4) obtaining seismic information, however basic, in every well in a cost-effective manner, which is important for future well placement and derisking drilling operations; 5) optimization of seismic acquisition programs in combination with conventional downhole three-component (3C) seismic tools; and 6) seismic data quality assurance resulting from measurement during the drilling process with minimum disruption (intermediate sections and TD), avoiding sections with multiple casing strings or noncemented tubulars. An example of a zero-offset VSP acquired on hybrid optical heptacable is discussed in the context of increasing drilling efficiency. The checkshot and VSP survey required only minimum rig time to acquire the data, with the hybrid fiber optic-conventional seismic program acquired at intermediate and final sections that obtained VSP information for the entire well with significant rig-time savings and improved data quality.

With known basement hydrocarbon accumulation, Mumbai High field in Western Offshore, India is a priority area for extending the concept of geo-mechanical fracture characterization in metamorphic basement reservoirs. Basement in Mumbai High is hydrocarbon bearing in areas proximal to major fault zones and intersections of major regional tectonic cross trends. Basement reservoirs have always been a challenge considering the lateral variation in rock properties with varying stress profile. The field under study has few wells producing hydrocarbon from varying depth intervals within Basement. Considering lower ROP, higher drilling cost and varying stress azimuth, a study has been conducted covering 3D Geomechanical numerical simulation and discrete fracture network stability analysis to identify sweetspots for new well locations targeting basement reservoirs while history matching field observations in offset wells. Basement reservoirs are often characterized by fracture sets which are conduit at present stress regime in far field condition. Some fracture sets are aligned within 20deg-30deg to maximum horizontal stress azimuth with few to be 90deg away from the maximum horizontal stress azimuth. To capture variation of fracture stability at field level, an analysis has been conducted at each offset well location, where geophysical logs, drilling parameters and geological information are integrated to construct a Mechanical Earth Model ( Plumb et.al, 2000 ). Rock mechanical properties are calibrated with available core test results. Horizontal stress profile has been estimated based on poro-elastic horizontal strain method and advanced far field shear radial profiles. Validation of 1D Mechanical Earth Models (MEMs) is conducted through predicted failure analysis and critical stressed fracture identification against drilling, production logging and testing results. A 3D MEM is constructed incorporating structural model, seismic velocity and 1D MEM based rock mechanical properties. The 3D principal stress field from the geomechanical simulation has been redistributed over fracture planes of Discrete Fracture Network (DFN) model to identify critically stressed fractures using a slip criterion. It involves estimation of parameters like slip tolerance and critically pore pressure change to understand the proneness of fracture/fault planes to shear dilation ( Barton et.al 1995 ). Stress regime varies from normal fault to strike slip fault depending on geological settings with maximum horizontal stress orientation varying between NNE-SSW to NE-SW. Analysis resulted in preparation of pseudo 3D sweet- spot maps governed by slip tolerance parameter indicating openness of fractures. It suggests that, most of the high angled fractures located in the proximity of intersection of faults are critically stressed subject to orientation reference to maximum horizontal stress direction and calculated slip tolerance. There is no specific azimuth of such fractures. Critical stressed fractures are present at varying depth: 50m to 250m from Basement top in the field as seen in offset wells where production logging and temperature data show good match of Hydrocarbon flow with predicted high slip tolerance fracture set locations. New locations with proposed well deviations and azimuths have been identified targeting the most probable prolific producers. The discussed multidisciplinary approach of fracture analysis has also been successfully used to predict and validate the contributing intervals in basement reservoirs of Mumbai High.

The resolution of seismic data in the semideep reservoirs ranging from 1500m to 3000m is low, and reservoir prediction is difficult when well data are scarce ( Xu et al. 2005 ; Liu et al. 2018 ; Pang et al. 2012 ; Wang et al. 2017 ). The sedimentary facies of the semideep reservoirs are mostly complex deltas, fan deltas, braided river deltas, etc. In addition, in the exploration evaluation stage and early development stage, the well pattern of offshore oilfields is sparse and well spacing is large. Especially in the early stage of oilfield development, well data are very few, so it is difficult to establish an accurate reservoir geological model. In order to solve this problem, this paper proposes a well-seismic integrated reservoir prediction technique based on seismic data frequency division processing and lithofacies distribution prediction technique based on sedimentary numerical simulation. On the basis of reservoir prediction, 3D reservoir geological modeling is carried out. With the reservoir prediction results as the constraint conditions, the sedimentary microfacies modeling is firstly developed, and then reservoir petrophysical modeling is carried out under microfacies constraints. The fine geological modeling of complex semideep reservoir is realized. Compared with the traditional geological model based on the constraint of 2D sedimentary microfacies map, the new modeling method has higher accuracy. The geological model established by the new method can more accurately predict the spatial distribution, porosity and permeability properties of reservoirs.

With the increase of well depth and recovery difficulty in oil and gas development, the downhole temperature and pressure rise unceasingly. The wellbore is simultaneously subjected on the non-uniform in-situ stress and high temperature and high pressure (HT&HP) under this complicated operation environment, which will seriously threat the wellbore integrity and bring huge economy loss. So, give a comprehensive analysis of wellbore integrity and propose corresponding prevention measures are of important significance for the safe and economic operation of HT&HP wells. In this paper, a new thermal-mechanical coupled model and analysis method for analyzing the mechanical response of casing-cement sheath-formation have been established. The model, which can be simplified to a plane strain problem, has considered the combined actions of temperature, pressure and non-uniform in-situ stress with appropriate boundary conditions. Subsequently, the corresponding equations have been deduced to obtain the mechanical responses of the model under the three kinds of actions mentioned previously. The wellbore integrity has been evaluated by proposed coefficient of failure (COF) defined by the yield criterion of Von-Mises, Drucker-Prager and Mohr-Coulomb. On this basis, the parameter sensitivity analysis of wellbore integrity is presented. With the increase of formation temperature and non-uniform degree of the in-situ stress, the COF of casing, cement and the contact surface of casing-cement decrease. The Poisson's ratio of cement has no impact on the COF of casing and the contact surface of casing-cement, while the COF of cement increase slightly. If the temperature variation is below 170°C, the cement ring cement is out of failure, and the wellbore integrity is under control. Besides, it is advantageous for wellbore integrity to keep the elasticity modulus of cement 10GPa-20GPa. This paper has a guiding significance for analysis and control of the wellbore integrity in HT&HP wells, which can allow the engineers to understand the casing failure and wellbore integrity more intuitively, and help them choose reasonable operation parameters to improve the operation life of HT&HP wells.

Many onshore oilfield development practices have proved that the integration of exploration and development is an effective way to avoid risks and improve benefits which is marked by phased development. However, the development of offshore oil and gas fields must rely on offshore production facilities such as floating production storage offloading (FPSO) units as well as production platforms. Once the offshore oil production platform is in place, future exploration, development and production operations must be carried out within a certain range of platform. The biggest challenge for offshore oilfield phased exploration and development is that the platform is far from potential oil and gas resources. Any drilling, evaluation, and development activities within the coverage of the platform are subject to the platform's design throughput, external transport capacity, number of well slots, etc.

In support of environmental monitoring technologies to evaluate the acoustic impact of marine energy operations, a cost-effective compact array of acoustic sensors has been developed that characterizes, classifies, and provides accurate location information for anthropogenic and natural sounds in real time. The NoiseSpotter consists of a three-dimensional bottom-mounted array of three acoustic vector sensors cabled to a surface buoy for real-time telemetry. Each sensor measures acoustic pressure and three-dimensional particle velocity associated with the propagation of an acoustic wave. The NoiseSpotter was deployed in an energetic tidal channel with a tidal oscillation that can approach 3 m. Performance characteristics in the presence of the resulting flow noise is quantified, and a flow noise suppression system is quantitatively shown to significantly improve performance, with flow noise suppression close to 15 dB. Performance is significantly improved when the sensors are housed in a flow noise removal shield, which provides acoustic transparency while reducing non-acoustic signal contamination. Long term durability of this flow-noise suppression shield is demonstrated using biofouling experiments. The real-time telemetry of data digests is demonstrated to allow rapid decision-making in response to measured sound intensity levels.

This research advances the use of microwave radar to assess geomaterial properties by the novel application of frequency modulated continuous wave (FMCW) radar to uniaxially loaded sandstones in the laboratory. Here contrasts in reflection coefficient are interpreted to represent microfracture formation and cross-linking under compressive loading prior to through-going sample failure. The Darney and Red St. Bees sandstones are characterized via optical microscope, X-ray radiography and tomography and by SEM methods and are tested for FMCW response under uniaxial compressive loads, with results showing that FMCW interrogation in the K-band is highly sensitive to the progression of bulk axial shortening and material bulk composition. The results reported here present an external, non-contact radio-frequency sensing modality using microwave radar to evaluate the samples as they are deformed. These samples are sandstones chosen for their distinct petrophysical properties and their significant differences in textural heterogeneity and anisotropy. This novel sensing application yields repeatable and consistent results, which are currently verified for four laboratory-deformed sandstone samples, where characteristic spikes in reflection coefficient, Γ, are observed. These spikes, which have not been observed in any other sensing modality, and occurring approximately 20 seconds prior to macroscopic yield, were observed in all samples tested. This research offers new insights into the evolution of deformation and failure in a porous geomaterial, here sandstone, and represents a departure from the current practices of post failure analysis. The effects of these new measurands (and how they change as a function of load) can be used to recognize more clearly the step-wise evolution of the sample progression to bulk failure and potentially be developed to provide a precursor warning of imminent sample failure. By increasing understanding of the damage development this can help refine the associated geomechanical theory. Better theory underpinning better calculations and simulations of a geomechanical reservoir issue can be critical in managing key seal and trap properties of a reservoir, enabling the operator to make improved operational decisions, increasing field productivity and production efficiency.

Offshore platforms, fixed or floaters, are a well-established design concept for oil explorations. It is fundamental to design these structures such that they can resist moderate to severe earthquakes without causing any severe damage to the occupants and to maintain the integrity of the structure. Hence, it is important to examine the behavior of these offshore structures for all kinds of earthquake scenarios to determine the risk levels that may occur in the structure. This paper intents to compare the seismic responses for a fixed offshore structure by employing ground motion records generated using three different methods. The design spectrum determines the seismic hazard of a region. Therefore, it is necessary to use acceleration records compatible with the design spectrum in seismic analyses. In this paper, Scaling, Spectral matching and Stochastic methods were used for comparison. Peerscaled tool was used for scaling in the time domain. RspMatch was used for the Spectral Matching. New acceleration records were generated by QuakeSim. A series of non-linear time histories using acceleration records of scaled ground motions were carried out to compare the damage levels and responses of a fixed offshore structure. Spectral matching method was observed to cause higher displacements than scaling method. The occurrence of inelastic events, such as buckling was observed to be high when the acceleration records considered the near-fault effect. And, permanent deformation was observed when acceleration records considered the fling effect. Ground motion records generated by different methods if adopted while performing seismic assessments of offshore structures will reduce the risk level for the structure.

Chevron has applied an increasingly robust approach to wellbore geohazards assessment over the Tahiti Field life. We discuss here how hazards assessment has evolved over nearly 2 decades. The last ~5 years we have applied a standardized approach to identify conditions of concern and incorporate knowledge gained from previous drilling results. Applying this approach, we have seen communication improvements among the Integrated Drilling Team (IDT). Results of the well-specific assessments assist in providing an informed and improved well design and drilling program. Retrieval of former drilling results though our lookback documentation has similarly seen benefit by employing this approach to documentation of events. Subjectivity of the assigned project team is minimized through the employment of standardized classification criteria. In order to tie-back to the drilling department metrics, we leverage geologic non-productive time coding and actual drilling events to qualify our consequence guidance not just within the Tahiti field but within the Gulf of Mexico Business Unit (GOMBU) and across the enterprise.

The Stampede Field is a sub-salt Miocene field in the deepwater Gulf of Mexico. Although it is a generally well imaged structure, development and production requirements warranted an improved image over the field. A variety of seismic data such as Narrow Azimuth (NAz), Wide Azimuth (WAz), and Dual Coil (i.e., Full Azimuth or FAz) have been used at various stages in the past. Imaging the field is complicated by the presence of up to 15,000 ft of salt which includes overhangs, inclusions, sutures, steeply dipping flanks, and a rugose base. Successful imaging of the northwest portion of the field has consistently been a challenge, regardless of the vintage or technique used in acquisition and processing. Recently, Ocean Bottom Nodes (OBN) seismic acquisition technology has become popular due to its long offset and low frequency content, which are essential to address complex imaging issues. In 2018, Hess engaged Fairfield Nodal to acquire OBN seismic over the Stampede Field, which recently started production. Acquisition design was based on an OBN modeling study. Nodes were placed over 238 sq km with shots over an 888 sq km area. The survey was safely executed without any incident or lost time. The data recovery was excellent. Data was processed with technologies including Full Waveform Inversion (FWI) for velocity model building and Least Squares Reverse-Time Migration (LSRTM). Dual coil and WAz data were used along with OBN to produce a superior image of the field. In this paper, we will discuss (1) the logistics of node acquisition over a producing field with infrastructure on the seabed and rigs at work and (2) the image uplift from processing the data using cutting edge technologies like FWI and LSRTM.

At present, China has three major deepwater oil and gas fields located in the Qiongdongnan and Pearl River Mouth basins in the South China Sea (SCS) at water depths ranging from 300 m to over 1500 m. In this paper we compare the geology, reservoir and fluid properties and development concepts of these deepwater fields with those in the Gulf of Mexico (GOM), Nigeria and Brazil. Based on this comparison, we have identified several key subsurface challenges and opportunities for future deepwater field developments in the SCS. Major subsurface challenges include smaller in-place volumes, heavier oil, lower reservoir energy and higher reservoir temperature. Opportunities identified include locating continental margin systems with high accommodation volumes and thick sandstone supply, use of alternative development concepts such as Floating Liquified Natural Gas (FLNG) and complaint platforms with dry tree wells and learnings from the recent development of lower-permeability reservoirs in deepwater GOM and the heavy oil deepwater developments and CO 2 handling techniques in Brazil.

Uncontrollable kicks are the most costly events that occur while drilling for oil and gas. Formation water flow sometimes turns to kicks that lead to life threatening and environmentaly disastrous blowouts. Prediction of the possible abrupt pressure surges that characterize the subsurface geological setting before drilling sheds light on some of the challenges that may be encountered along the bore-hole trajectory. This will also help curtail human error during penetration of certain zones along the well-hole trajectory, and consequently reach the objective depth safely and with less nonproductive time (NPT). Before drilling, pore andfracture pressure predictions from seismic velocity are critical for assessing the economic feasibility and safety for the whole prospective trap. Integrating the seismic velocity drifts and the sequence stratigraphy semblance at the proposed location can point to the possible pressure transgressive intervals that can cause a sudden pressure surge (PS). Moreover, modifying the drilling tolerance window (DTW) to accommodate the expected hydrocarbon column in the prospective reservoirs reduces the potential of unexpected hard kicks at the shale – sand interface. This paper briefly discusses the impact of subsurface geopressure compartmentalization on seismic velocity drift and consequently on PS. It also examines the subsurface geological setting that can cause substantial pressure increase penetrating the lithological interfaces. Therefore, the pressure transgression and expected excess pressure in pay zones should be encompassed within the numerical algorithm of the predictive model before drilling. Monitoring the logging while drilling (LWD) data slopes in shale beds can successfully point to a possible kick ahead of the drill bit. Maneuvering the mud weight and casing program while drilling within the DTW based on the modified numerical pressure profile can achieve safe drilling. Examples from onshore and deep-water wells are shown. This paper covers several geological features that correlate to open bore-hole flows or kicks that sometimes develop to a blowout if the formation flow is not controlled by the right mud weight kill. Detecting these subsurface features and their associated seismic velocities before drilling can lead to safe drilling and avoiding NPT. Moreover, this paper sheds light on the potential to enhance drilling safety in advance, even in cases where managed pressure drilling (MPD) equipment is used.

As vibratory driving is increasingly used to install offshore foundations, especially for offshore windfarms, an accurate soil model is key to reliable pile driving predictions and thus to improved project planning and execution. During the pile driving, the soil properties, and thus the soil parameters, do not remain constant. For vibratory driving, this effect is generally simplified by the application of the Beta Method, which was first proposed by Jonker in 1987[ 1 ]. While this simplified approach could be justified based on the computing capabilities at that time, a more sophisticated soil model should be used as part of pile driving simulations to ensure that the results are more accurate. In this paper, the state-of-the-art soil model for vibratory driving will be described and then illustrated through two brief case studies where the pile driving simulation results are compared with the actual installation records. The paper will show that while the predictions are not perfect, they forecast the pile driving process realistically. To further enhance prediction capabilities, the paper will suggest that pile driving with vibratory hammers is monitored and that the recorded data be used for post-processing to gain a more in-depth understanding of the soil behavior.

The characteristics of a primary well pattern in offshore oilfields are: large well control reserves, large well spacing, thin well pattern, multi-layer combined production and develop highest quality reserves. Infilling adjustment project is of great significance for field life extension, full utilization of facilities, efficient production, remaining oil tapping, well pattern improvement, water flooding optimization, reservoir pressure maintains and production stabilization for offshore This paper takes an oil field in Bohai as an example to analyze the potential and risks of the infilling project.

The objective of this paper is to show a methodology that generates a secondary guide for propagating fracture densities as input to a DFN (Discrete Fracture Network). Our goal is to provide a new idea for geomodelers who deal with complex fractured fields, and do not have enough information to build robust models for exploration and simulation. The secondary guide was developed to help geomodelers populate fracture properties on a reservoir model. The seismic data was of low quality, making it difficult to obtain good seismic attributes. Therefore, a guide was created that incorporated on the same attribute, information about the geocellular grid deformation, the distance from the fault planes, and the fault's displacement. All of the information used to generate the secondary guide was created from the structural model (interpolated surfaces -faults and horizons - perfectly sealed) and geocellular grid. It is also important to know that, depending on the type of deformation defined for the model, deformation results can vary. Once the three properties were calculated and placed in the same domain (the geological grid), they were rescaled. After that, they were merged in a new property according to the geomodeler's criteria. The quality of the results relied on the seismic interpretation of faults and horizons, so in order to generate a good guide, it was important to obtain the most accurate representation of the structural model. The values of the new output property varied as a function of the distance from the faults, but also as a function of the fault displacements, and the presence of the deformed rock. This allowed its correlation with the fracture density through use of a statistical function. The secondary guide did not include other fracture controllers, such as the probability of fractures, which was also controlled by the geomechanical parameters. That would be another property to be weighted in the process. The process was designed and applied to a real case. The methodology enabled the geomodeler to distribute fracture densities and their properties without the use of seismic attributes. The workflow is applicable to any kind of fractured reservoir and can be used anywhere, from exploration to production.

Prior to 2007, the U.S. Department of Energy (DOE) upstream oil and gas research program focused primarily on onshore applications. In 2000, the DOE published the Offshore Technology Roadmap for the Ultra-Deepwater Gulf of Mexico . Then, the Energy Policy Act of 2005 required the DOE to expand its research portfolio to include ultra-deepwater research. DOE has continued this offshore research focus to the present, and this paper presents an overview of past accomplishments and results, the DOE's current research portfolio, and outlines the potentially key elements of a technology roadmap for the entire OCS. Discussion focuses on key research findings from the DOE ultra-deepwater research portfolio of 2007-2013. Then the paper describes the current offshore research portfolio 2014 – 2019. Finally, the paper describes the outcomes and insights from key discussions with industry, academia, research and non-government and government stakeholders that could become a frame for a technology research roadmap for the entire Outer Continental Shelf. DOE research investments in public-private partnerships with industry, academia, research labs, and others have made an important contribution to the current state-of-the-art in offshore technology---contributions that most people may not realize are tied to previous research investments by DOE. Tracing these contributions, tracking them back to the Offshore Technology Roadmap for the Ultra-Deepwater Gulf of Mexico published in November 2000, and framing a technology research roadmap for the OCS will demonstrate the value of public-private partnerships. The information in this paper will both inform and inspire new frontiers of research for the OCS. As the USA moves forward with onshore development of unconventional resources, there are features of the DOE onshore research portfolio that may have merit in the OCS. For example, the DOE Field Laboratory program is focused on basin-specific research strategies where new technology can be applied to operating oilfields and evaluated via the scientific method. Then the data captured can potentially become part of further research by the DOE National Laboratories including geophysical, geomechanical, geochemical, and data analytics such as machine learning. This DOE program has been very successful onshore, and perhaps there is a place for a comparable multi-disciplinary, multi-partner approach in the OCS.

For subsea structures placed on soft seabed comprising fine-grained sediments, geotechnical design may be equally governed by the foundation settlement and stability requirements. For this reason, the soil stress history parameter, i.e. yield stress (σ y ), becomes as important as the strength parameter, i.e. undrained shear strength (s u ). Common practice in characterisation of fine-grained sediments focuses more on deriving the s u profile than on evaluating the σ y profile. More often, the underlying connections between these two important parameters are overlooked in the interpretation process. As a result, the selected design line of σ y may be incompatible to that of s u . This paper presents a balanced characterisation of fine-grained soils, focusing on interpretation of in-situ s u and σ y using a coherent and simple framework underpinned by the Stress History and Normalised Soil Engineering Properties (SHANSEP) relationship. Interpretation procedure, performance and advantages of the proposed framework are demonstrated by a real application to an offshore site dominated by fine-grained carbonate sediments. In this framework, the two SHANSEP parameters, including normally consolidated normalised strength ratio (S) and empirical constant (m), need to be quantified for the site of interest. This is achieved by performing a series of laboratory strength and consolidation tests on undisturbed samples, with the strength tests being performed respectively under in-situ and elevated stress conditions for determining in-situ s u and the values of S and m. Once the SHANSEP parameters and the s u profile are derived, the σ y profile can be calculated. These two profiles can then be refined further by comparing against the measured s u and σ y at discrete depths respectively from the strength and consolidation tests. Since this proposed framework allows the user to consider the results from the in-situ and laboratory tests (including both strength and consolidation tests) holistically, more reliable and coherent interpretation of the s u and σ y profiles can be achieved. In addition, the framework allows for an easy estimation of consolidation-induced strength gain due to the permanent load applied by the subsea structures by simply using the derived σ y profile and updating the vertical stress in the parameterised SHANSEP relationship. This may reduce the conservatism in the foundation design and provide optimisation opportunities.

Geophysical seismic surveys have been applied to marine geo-site characterization to create images of the complex geological conditions under the seafloor. Accurate knowledge of the ground conditions is critical for geo-risk assessment purposes such as mapping shallow gas hydrate deposits, over-pressured zones, or geological anomalies. Traditional seismic reflection profiling is a relatively fast and flexible method of processing seismic data to recover information on the spatial variation in facies boundaries and subsurface structure. However, the method usually does not provide quantitative information on the composition of the sediments and their physical properties. Seismic inversion is a method to convert the wave signals from time-to space-domain and derive specific material properties by using iterative numerical modeling. In this paper, we introduce a probabilistic seismic inversion scheme to recover the vertical profiles of the shallow soil bulk density from marine seismic survey data. This acoustic impedance inversion is based on the geophysical seismic convolution method and the reversible jump Markov chain Monte Carlo (rj-MCMC) method. The rj-MCMC is a recently developed stochastic sampling technique that allows the modeling to free the number of layers under the seafloor. Hence the number of soil units is estimated from the data in an objective manner. We applied this new approach to a single trace of post-stack seismic data, collected from the Hydrate Ridge area on the west coast of Oregon. Since the purpose of this shallow seismic inversion is to support the design of the offshore foundation, we focused on the relatively short length of seismic signals near the seafloor. The inverted results of the bulk densities along the depth compare well with the field measurements performed at the nearby drilled borehole. This study introduces an advantage of the probabilistic seismic inversion approach to support shallow marine site characterization from low-frequency data, and we discuss the benefits of this new approach on geotechnical site characterization.

Extending the geohazards assessment throughout the overburden section above the main reservoir is a relatively recent practice. Traditionally, a geohazards assessment for the riserless section of wells has been a key element of pre-drill studies in offshore well planning. Potential geohazards such as seafloor/buried faults, gumbos, gas hydrates, shallow gas and shallow water flow are routinely investigated using seismic reflectors, seismic amplitude, extent of well-known problematic stratigraphic units, and offset wells drilling data. As a result, the understanding of the regional distribution of geohazards has increased significantly. Although the common geohazards as mentioned above are well known, the assessment has been challenging with deeper depths. The loss of seismic resolution with depth affects the interpretation of the stratigraphy, structure, pore pressure and fracture gradient. The uncertainty in the depth and inclination of key marker events including stratigraphic horizons, chronostratigraphic ties, etc. might lead to a wide margin of possible pore pressure and fracture gradient (PPFG) estimates. The velocity-effective stress transformations used for pre-drill PPFG from low resolution seismic data is also less reliable, compounding the error resulting from predicted stratigraphic markers (horizons). Seismic interpretations with low resolution are inadequate to identify thin over-pressured zones. The paper presents an integrated workflow that maximizes the predictability of geohazards for the entire reservoir overburden section. A variety of seismic volumes including amplitude reflection, amplitude versus offset (AVO), seismic inversion, seismic velocity, coherence data, etc. allows for the optimization of interpretations such as stratigraphy, structure, and rock properties. A detailed geologic model with advanced seismic processing techniques provides a high-resolution understanding of structure and stratigraphy, seismic attribute distributions, and spatial velocity variations. The model is useful to identify key faults, leak points, sealing intervals, and trapping mechanisms. Understanding the stratigraphic facies assists in mapping the intervals of pressure generation and retention zones. Considering these limitations, offset well data is integrated when available and utilized to characterize seismic facies and rock properties in sparse data environments. These data are then correlated with seismic reflection and velocity data to develop a well-constrained geologic model. Multiple types of seismic volumes with various frequencies, coverages, and penetration provide better control and understanding of the riserless section. This may include AVO and inversion volumes, which are not commonly used in a shallow geohazards assessment. Finally, a fully integrated geohazards assessment, from the seafloor to the main reservoir, results in an optimized drilling program and is developed to minimize the impact of geohazards and drilling risks along the wellbore trajectory.