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.

This laboratory study explores the geophysical imaging applications of a fiber optic sensing system in a marine environment, from fiber installed on pipes or casing to fiber laying on the floor. The most common application with fiber installed on casing is borehole seismic imaging. With fiber laying on the ocean floor, surface seismic imaging is a possible application. This is tested in a laboratory setting using a Distributed Acoustic Sensing "DAS" system, Fiber Bragg Grating "FBG" system, and a conventional geophysical hydrophone system. A setup is made using PVC pipes and a water-filled tank to simulate a marine environment, and the sensing systems were distributed along the pipes and on the tank floor. Single mode telecommunication fiber was laid out on the tank floor and the pipes, which consist of a vertical pipe segment and a horizontal pipe segment. The pipes are connected to a water reservoir to allow flow from the reservoir through the vertical pipe then the horizontal pipe into the tank. An array of FBG sensors were distributed along the pipes and some were left floating in the water. A hydrophone array was secured to the vertical pipe segment and distributed along the horizontal pipe segment to make conventional geophysical imaging measurements. Seismic sources with different frequencies were used, a piezoelectric transducer was used to introduce higher frequency (ranging from 500 Hz to 25 kHz), and a hammer source was used with different material as broad frequency sources. The measurements made were compared across the sensing systems and the frequency response was used to evaluate the preservation of the source frequency signature on the sensing instruments. The DAS system was sensitive to low-frequency ambient noise which made it difficult to see the frequency response of the seismic sources, however, it was useful in capturing the higher range of frequencies. The FBG system showed better results in capturing lower frequency signal but was limited by the high frequencies it could capture. Nevertheless, the captured high frequencies exceeded the frequency range of interest for seismic imaging but are useful for applications of wireless communication using fiber and PZT transducers. Therefore, both systems can capture the response of the seismic sources for imaging but with different noise sensitivity. The results presented in this study indicate that a fiber optic sensing system can be used for seismic imaging in an offshore environment. Further tests are recommended in larger scale environments to confirm the findings of this study. The advantages of using a fiber optic sensing system are highlighted in this study. Finally, further applications to wireless communication via fiber optic sensors and high-frequency transducers are discussed.

Understanding the stimulated reservoir volume and mapping hydraulic fractures away from the wellbore remains one of the biggest challenges in unconventional plays development. Currently available production logging and tracer technologies have shallow depths of investigation—only a few inches beyond the wellbore. Far-field microseismic mapping offers an image of micro-earthquakes that are caused by shear slippage during a hydraulic fracture treatment. Although the location of the associated microseismic events enables spatial mapping of the stimulated rock volume, particularly its orientation and growth characteristics, the microseismic deformation does not provide direct information about hydraulic fracture effectiveness. The latest improvement in deep shear wave imaging processing (DSWI) provides a visual representation of geological features up to 100 feet from the wellbore. DSWI nicely fills the resolution space between conventional near-wellbore diagnostic technology and far-field microseismic mapping. The shear wave azimuthal sensitivity enables estimation of the hydraulic fracture geometry away from the wellbore. It also provides direct visualization of the actual reservoir volume that has been stimulated in the mid-field region with the extension of hundreds feet from the wellbore. This paper presents a case study of the post-hydraulic fracture diagnostic in a shale reservoir using deep shear wave imaging technology. The information derived from the pre- and post-hydraulic fracture imaging enables a better understanding of the stimulation treatment effectiveness and fracture propagation away from the wellbore. This imaging can also be used for the completion optimization of the new drilled wells, as well as for the identification of previously unstimulated zones for re-fracturing. The accuracy and credibility of the DSWI hydraulic fracture diagnostic was confirmed by running a cross-dipole acoustic log in a well with high water cut. Radioactive material present in the produced water caused up to 150 API increase in the gamma ray activity due to precipitation associated with the pressure drop in a hydraulic fracture. The study showed that the lateral intervals with a substantial increase in gamma ray activity matched the hydraulic fracture locations identified by the DSWI process. These case histories highlight the value of the information obtained from the DSWI to enhance the fracture optimization, to improve ultimate recovery, and to reduce overall operational cost.

The Stones asset is an ultra-deepwater development located approximately 200 miles south of New Orleans in ~9500 feet of water . Final investment decision was taken in 2013, with first production achieved in September 2016. This development is part of the frontier Paleogene outboard play in the Lower Tertiary Trend that targets the Upper and Lower Wilcox formations. In early 2014, a change management program was kicked off, originally centered on minimizing well construction risks. This change management program was organically grown, with cost and risk baselines being re-assessed bottoms up, and key opportunities identified. Major improvements were obtained in the areas of minimization of risk and capital investment during the period of 2014 to 2016. Improved risk and cost themes centered on: (a) enhanced trade-off between subsea and well construction complexities; (b) improved subsurface imaging to increase flexibility in well trajectories; (c) deepened integration between completion choices and well designs; (d) technical functionality rationalization; and (e) supply chain improvements. This paper highlights the key change management lessons learned that took place during the Stones project execution resulting in the project meeting the cost promise from project sanction.

Deep water Ocean Bottom Node (OBN) systems have delivered high quality full azimuth 3D and 4D seismic data. In this paper, we discuss the development of a new node technology and a new method of employing nodes for reservoir monitoring, wherein, a high-speed underwater optical communications system is utilized to extract data from nodes that have a long deployment capability, without recovering the nodes from the seafloor. This highly repeatable semi-permanent 4D monitoring capability can be implemented at considerably lower cost than with cable based Permanent Reservoir Monitor (PRM) systems. Full azimuth and long offset seismic data acquired with a sparse array of ocean bottom nodes and a dense patch of shots has proven to be a very successful technique for both 3D and 4D imaging below complex salt overburden in the deep water Gulf of Mexico, where more than 25 OBN surveys have been conducted in the last ten years. Deep water OBN 3D and 4D surveys have also been successfully conducted in offshore West Africa and Brazil. Autonomous deep water OBN systems are proven to be very reliable, with 98+% data recovery, and nodes are routinely deployed by a remotely operated vehicle (ROV), amongst field infrastructure and simultaneous operations. Also, for reservoir monitoring, OBN surveys are proven to be highly repeatable, resulting in low 4D noise, NRMS statistics typically less than 10%, which is comparable with that achieved using PRM systems. We are motivated to look for ways to extend current proven node technology to semi-permanent reservoir monitoring in deep water (> 500 m), where the cost and technical, logistic and HSE challenges for PRM installation amongst the infrastructure of a working field are high. Installing a group of autonomous nodes, which is routinely done today, is an attractive alternative to the complex integration of a cabled system with existing facilities. By semi-permanent, we mean the nodes are deployed once, and then multiple surveys are acquired over an extended period of time, before recovery. For this purpose, we have designed and built a node which has sufficient energy storage for a five year on-the-seabed lifetime and a 300 day active recording life, enough for 12 surveys (baseline + 11 monitors) – each having a duration of about 25 days. An enabling technology that makes the semi-permanent Life of Field (LoF) node possible is a proprietary high speed underwater optical communications technology, whereby, data download from the node is performed in situ on the seafloor. Nodes are deployed in "sleep" mode and when needed they are remotely switched on, "health" checked for operational readiness, synchronized with a reference time signal, and have their recording systems activated. Upon completion of the active source period, each node is re-visited to extract the seismic data via the optical communication system and then switched off until the next monitor survey, all without handling the node, but by closely approaching the node with an ROV or an AUV (Autonomous Underwater Vehicle), to effect the optical link.

The trend towards frontier deepwater (FDW) exploration plays around the world creates new challenges for seismic data acquisition, processing and interpretation. Technical challenges focus on the need for high-quality seismic data to allow good understanding of geology from seafloor to target - so as well as providing an image of the drilling targets, the seismic survey is must deliver reliable information about the overburden to mitigate drilling surprises. In addition, economic challenges reflect the need to acquire data over large areas in a cost-effective manner, but without compromising data quality. This paper reviews a new class of marine seismic technology that aims to address these previously contradictory demands. The technology is based on multimeasurement streamers that combine traditional hydrophone (pressure) measurements of the seismic wavefield with densely spaced accelerometer measurements that derive the wavefield gradient in vertical and horizontal directions. These measurements are combined to perform dense seismic wavefield reconstruction. The results provide greater detail of the seismic wavefield between the streamers and build a true 3D representation of the seismic wavefield that is equally and finely sampled in all directions. In the context of FDW exploration, this offers two main benefits. The first relates to the ability to generate high-resolution earth models of the overburden, where fine-scale isometric subsurface characterization can help define safe and efficient well trajectories. This offers protection against noise and other artefacts in the seismic data, which, despite the typical characteristics of ultra-deepwater environments, may otherwise introduce interpretational uncertainty. It also mitigates inaccuracies and bias in the shallow velocity model impacting the deeper earth model construction. Secondly, the ability to accurately reconstruct the seismic wavefield between streamers presents options for acquiring data faster, more cost effectively, and with less operational and environmental exposure. For example, using two- and three-boat operations to double or triple subsurface coverage with a single recording vessel. A selection of examples using real and modelled data will be used to illustrate both these key aspects. Successful seismic imaging for FDW means understanding the pathway to the target reservoir as much as the target itself. A broad technology portfolio is required to provide integrated workflows, and multimeasurement seismic acquisition can be a key component in the solution; addressing aspects of enhanced resolution, wavefield sampling, and 3D deghosting, whilst also providing options to acquire data more efficiently without compromising quality.

The super-giant ACG field lies in the Azerbaijani sector of the south Caspian Sea. Since the signing of the "Contract of the Century" in September 1994, the significant complexity of the geohazards setting over this field has required near continual acquisition of geophysical imagery to better understand the various geohazard issues faced. Upon signing of the PSA it was known that there was very little geophysical imagery of the shallow section in existence. As such, the first geophysical operation over the PSA contract area in 1995 was a blanket regional 2D survey of the entire 450km 2 PSA contract area to allow regional geohazards mapping to be undertaken. This entailed acquiring a regional grid of HR2D seismic data and a seabed survey that included collection of swath bathymetry. The challenges of importing acquisition systems into Azerbaijan, and mobilizing the equipment onto vessels of opportunity, limited the systems that could be used at the time. Therefore, the bathymetric model that was produced, for example, was useful, but limited by a swath bathymetry system that could only image to ~210m of water depth while PSA contract area water depths vary between 96 and 425m. Over the following decade, geophysical site investigations of appraisal wells, platform sites and pipeline routes followed industry norms of site specific 2D surveys. However, in 2004, one pass HR3D and seafloor surveys were acquired making use of a 3D seismic vessel. The use of the larger vessel had various advantages. Firstly, the capability to safely tow four streamers and two sources allowed acquisition of eight lines of subsurface coverage per sail-line. Secondly, the more stable vessel platform, allied with a more robust design of over-side mountings, provided a far superior platform for acquisition of swath bathymetry data. The resulting seabed and sub-seabed imagery were far superior to preceding imagery. In 2007, another step change in data quality was achieved with the acquisition of the first ever deep-water AUV survey acquired in the Caspian Sea. Using a Hugin 3000 vehicle, the resulting swath bathymetry, sonar and sub-bottom profiler imagery saw another step change in quality. HR3D and AUV data of the entire PSA have now been acquired in a phased approach. Included in the HR3D acquisition were undershoots of the six producing platform complexes to verify the integrity of overburden conditions below the platforms. This paper will show the improvements in data quality that have been achieved over life of the PSA, and demonstrate the impact these improvements have had on better understanding of geohazards for future development and ongoing operations across the field.

We present a seismic processing workflow that significantly improves subsurface images of hydrocarbon targets in shallow water. Our workflow is dependent on an integrated velocity model building toolkit, which works well for salt geometry and sediment velocity model building. The workflow addresses the challenges associated with complex salt structures and produces an improved subsurface seismic image in the complex salt province. A real case is presented here to demonstrate the workflow.

Abstract In marine oil and gas exploration of seismic data acquisition, both primary and multiple reflections are recorded at the streamers. In seismic data processing, primaries are usually used as signal to image the subsurface; multiples are regarded as noise to be removed (SRME) (Verschuur, 1991). Multiples can also be treated as useful information to image the earth. The idea of using sea surface related multiples as valuable information for depth migration has been discussed by Berkhout and Verschuur (1994), Guitton (2002) and Whitmore et al. (2010). Lu et al. (2011) presents the first 3D example of imaging sea surface related multiples using towed streamer acquisition geometry. Conventional shot domain migration constructs a subsurface image by combining the forward extrapolated down-going wavefield from a source location and reverse extrapolated up-going wavefield originating at the surface receiver positions. Similarly, sea surface related multiples can also be used for imaging the subsurface where the boundary data for the down-going and up-going wavefields are generated at the receiver locations via up-down wavefield separation. After up-down separation, the down-going and up-going wavefields act as the source and receiver surface wavefields and exist at the receiver positions. Compared to primaries imaging, multiples imaging can help to enhance subsurface illumination in depth migration; because the source wavefield (down-going wavefield) of multiples imaging is more broadly distributed than the source wavefield of primaries imaging. More significantly, multiples imaging improves angular illumination by using additional source wavefield coverage. In this paper, 3D field data examples are used to compare imaging of primaries and imaging of multiples. A shallow water field data example shows the successful application of the technology to mitigate the acquisition footprint and generate very high resolution images. A deep water field data example demonstrates the opportunity of the technology to improving subsurface illumination and angular illumination when applied to wide azimuth acquisition. By enhancing subsurface illumination in depth migration, the technology has the potential of improving quality of subsurface reservoir characterization and reducing drilling hazard risks.

Abstract The objective of seismic acquisition and imaging is to recover the true properties of the earth. Major obstacles to obtaining this ideal goal are: the bandwith of the emitted source signals, the spatial sampling of the seismic survey and spatial aliasing, the aperture of the recorded data, the ghost effects on the source and receiver sides, the external and internal noise and the ambiguity (nullspace) of the inversion problem (Yilmaz, 1987).

Abstract Lockheed Martin has developed the capability to conduct AUV-based structural survey and post-hurricane platform inspection using 3D mapping and change detection with a 3D sonar. Successful validation trials for this technology were conducted with the Marlin® AUV during the summer of 2011 and the first commercial operations were conducted in the summer of 2012. Lockheed Martin Corporation, in partnership with underwater laser developer 3D at Depth LLC, and supported by funding from the Research Partnership to Secure Energy for America (RPSEA), is now extending its revolutionary 3D modeling and change detection to employ a 3D laser sensor, thereby improving model resolution and accuracy by an order of magnitude, from centimeter scale to millimeter scale. AUVs outfitted with 3D Laser imaging systems will provide new, high accuracy tools for subsea integrity management that are currently used extensively in terrestrial applications, including High Definition Scanning (HDS) for close-in inspection of problem areas, and underwater LIDAR (LIght Detection And Ranging) for 3D mapping and inspection of flowlines, risers, and other subsea infrastructure. The scope of this project is to develop and demonstrate the technology required to conduct AUV-based 3D-laser imaging utilizing 3D mapping and change detection. Objectives include demonstration of close-in, high resolution underwater structural inspection, generation of high resolution 3D models of subsea structures, and performance of change detection of flaws or damage against a priori structural models. This paper will detail the results achieved to-date and will highlight the 3D Laser performance improvements over current platform inspection methods, including significant improvements in operating efficiencies and the development of accurate 3D models for use in structural integrity management.

Abstract Seismic waves propagating in the earth are affected by attenuation. Attenuation is the progressive loss of energy with each cycle of the wave. The resulting seismic data has a frequency and time dependent loss of amplitude and a phase rotation of the wavelet. Traditionally attenuation has been compensated during the preprocessing, however this approach has a number of limitations. It is difficult to relate the recorded seismic trace to a location in the subsurface and hence except in the case of a constant attenuation factor the amount of attenuation correction to apply is difficult to identify. Correcting for attenuation during the model building and imaging stages of processing creates the opportunity to relate attenuation factors to the subsurface model and hence have geologic constraints on the attenuation factors and permits the application of a attenuation correction associated with propagation of the energy through the subsurface. Additionally the attenuation corrections introduce phase shifts into the data that can create biases in the velocity model if they are not rigoroulsy handled in the model building process. Ideally the incorporation of attenuation is handled within all aspects of the model building and imaging. Our experience indicates that incorporating attenuation in this manner results in a more rapid convergence to a more accurate model, especially in the shallow section. Improvements in the shallow section will impact the ability to accurately image and interpret high contrast boundaries in the subsurface such as a salt interface and improvement to the imaging and positiong of such boundaries results in improved imaging of the deeper data to varying degrees. Statement of Theory and Definitions Attenuation of the seismic wave at a location in the subsurface is defined by the Q factor of that particular part of the subsurface. The Q factor is defined as the 2 p times the total energy stored divided by the energy lost in a single cycle. Higher frequencies are reduced in amplitude more for the same traveltime than lower frequencies, so as we progress deeper into our data the dataset becomes progressively reduced in bandwidth and lacking in high frequency components. Consequently the amplitude at a given time can be related to the initial amplitude as follows: A(t)?A_0 e^(-?t/2Q) where A_0 is the initial amplitude, ? is the angular frequency and t is the traveltime. In addition to the loss of energy and reduction in amplitude as the wave propagates there is an apparent frequency dependence of the velocity. The apparent velocity variation or phase rotation is rigorously handled in the methods we use to propagate energy (Bai et al, 2012, Blanch et al., 1995). For a general understanding there are several approximate models that enable a quantification of the magnitude of this affect (Futterman 1962, Azimi et.al. 1968). Higher frequencies propagate faster with relatively rapid changes in the velocity at low frequenices

Abstract In recent years, it has become the standard practice in deep water Gulf of Mexico (GOM) to perform seismic imaging assuming tilted transverse isotropy (TTI) symmetry to describe the anisotropic effects of wave propagation in salt-withdrawal mini-basins. When compared to isotropic and vertical transverse isotropic (VTI) imaging, TTI prestack depth imaging generally provides flatter common image gathers (CIGs) for wide azimuth data, improves image focusing, and significantly reduces well/seismic mis-ties. This anisotropy is thought to arise from the geometry of sedimentation processes, with the " tilt" applied by subsequent tectonic activity. However, the presence of significant tectonic stress or uneven stress can cause fractures in thin-bed layers, which results in a further directional velocity variation for seismic wave propagation, or azimuthal anisotropy around the bed normals. In these cases, the transverse isotropic assumption is insufficient to explain conflicting residual moveouts among CIGs of different azimuths from TTI imaging. A more general anisotropic model, tilted orthorhombic (TOR), is needed to cope with azimuthal velocity variation in these complex geological settings. In this paper, we apply TOR model building and migration to an area in the Green Canyon area of central GOM with the aim of improving the subsalt image. Two orthogonal GOM surveys, one narrow azimuth towed streamer and one wide azimuth towed streamer, are used to derive both TTI and TOR models. With the TOR model, we observe improved gather flatness among azimuths, better well ties, and improved salt imaging - all of which lead to more accurate delineation of salt geometries and, consequently, better imaging beneath the salt. We infer that tilted orthorhombic provides better a representation of an overburden with fractures and uneven stress. Through improved overburden velocities, TOR reverse time migration produces better subsalt images. Introduction Considering available NATS surveys and the recent surge of WATS acquisition, the Gulf of Mexico (GOM) is now crisscrossed by abundant data. WATS data is often combined with existing NATS data to form Multi-Azimuth (MAZ) coverage that provides additional azimuthal information. This abundant information can improve subsalt illumination by providing better constraints for deriving accurate anisotropy parameters. Pre-stack depth imaging workflows incorporating Tilted Transverse Isotropy (TTI) with MAZ are now common practice in deep water Gulf of Mexico for compensating for the anisotropic effects of salt-withdrawal mini-basins (Lynn and Michelina, 2011). TTI RTM (Zhang et al., 2011) improves image focusing, particularly along steeply dipping salt flanks and the subsalt region underneath mini-basins (Huang et al., 2009, and Bowling, 2010). However, TTI is a simplified representation of elastic media; it assumes the wave propagation speeds are the same in all directions in the transverse plane (Thomsen, 1986). In fact, this may be an oversimplification in some GOM areas with significantly uneven stress and fractures. Despite our best TTI-compliant practices in these areas, we observe inconsistent residual moveout in common images gathers (CIGs) along different azimuths.

Abstract Kaombo is a multi-field development on block 32 in Angola. About two thirds of the block is covered with a salt canopy that strongly degrades visibility of the hydrocarbon traps. This lack of visibility prevented a good estimation of the resources and their distribution in several subsalt areas during the very first years of exploration. However, this last decade has seen a dramatic improvement in seismic processing, enabled by the increase in high performance computing capabilities of the industry. Through examples of subsalt fields of the Kaombo project, we show how new techniques have had a positive impact for exploration and development. These new techniques can be put into three categories that we illustrate in this presentation. First, use of more complex and accurate pre-stack depth migration (PSDM) algorithms through time was made possible by the increase of high performance computing capacities. Second, new acquisition techniques such as wide-azimuth have improved the illumination of the subsurface, filling gaps in the images. Lastly, progress in depth imaging led to a better understanding of the structures, which improved the description of the subsurface. This better description, in turn, had a positive impact on the production of new images. Today, new techniques continue to emerge. For instance, calculation of reverse-time migration (RTM) surface offset gathers enabled an improvement of the stack quality. Full waveform inversion was also helpful to define the shape of the salt in some areas where the imaging is still challenging. Progress in subsalt imaging is the product of many improvements. Although the contribution of any single step is sometimes not spectacular, the combination of all of these though time display a step change in depth imaging since the early days. Without it, development of subsalt fields such as Kaombo would not be possible. Introduction The Kaombo project is a multi-field development on block 32 in Angola. Tertiary turbiditic reservoirs are located below a salt canopy that has historically been a challenge for standard imaging techniques. Unlike other blocks of the Lower Congo basin that are more proximal to the shore, a shallow canopy of complex-shaped salt bodies below the sea surface covers about two thirds of the block (figure 1). The salt bodies create strong lateral seismic velocity variations that are highly detrimental to classical time processing approaches. Thus, prospect maturation work during the early days of this block (1999–2001) was focused on targets outside of the salt influence. While its application was initially restricted to a few areas for cost reasons, PSDM rapidly became the standard exploration tool on the block (2002–2004). These first stages of subsalt explorations involved Kirchhoff and common azimuth wave equation migrations (CAM, Biondi and Palacharla, 1996), because of their relatively low computational cost, applied to a 3D narrow-azimuth dataset. Migrations were performed using simple isotropic velocity models and a priori salt models where the salt geometry could not be assessed with certainty. The quality of the images was improved compared to standard time processing, but some work remained to increase the probability of success of subsalt prospects (figure 2) sufficiently enough to drill these prospects.

Abstract Until very recently, the petroleum system of Brazilian presalt reservoirs could not count on good enough seismic imaging to support the seismic interpretation. In the 90's, the decision of Petrobras to expand its exploration frontiers towards the sedimentary basins of EspÍrito Santo and Santos brought forth new efforts to improve the existing 2D seismic imaging. The favorable outcome of this campaign motivated the 2001 decision to acquire a 3D program covering potential exploratory leads. In 2005, Petrobras and its partners began exploratory drilling in presalt reservoirs, culminating in the discovery of the Lula-Iracema (2006) and Sapinhoá (2008) fields and other areas: Iara, Carioca, Júpiter, etc. In 2008, as a consequence of these results, Petrobras started oil production from the Brazilian presalt province. In 2008-2009 a high density 3D seismic program was acquired over these areas and state-of-the-art seismic processing technology was applied in Santos and Campos basin. In 2010-2011 a full-azimuth acquisition project took place east of Iara area (circular streamer acquisition), an orthogonal OBC project was acquired in Campos basin and also some borehole seismic projects (walkaway, walkaround and 3D VSP) were performed in Santos basin. The seismic processing flow evolved from building isotropic velocity models to anisotropic ones, with the use of in-depth imaging techniques such as TTI PSDM. An important processing challenge has been to improve the interbed multiples attenuation. Moreover, the seismic data processing and full-azimuth 3D VSP have been enhanced by focusing on improved imaging and characterization of Brazilian presalt reservoirs. Several processing methodologies were used, including in-house algorithms/workflows in addition to service companies' solutions. The seismic characterization of the presalt reservoirs has made extensive use of inversion techniques, seismic facies and seismic attributes extraction from the inverted data with very good results. The results of elastic inversions are still a challenge. Another major challenge will be the implementation of 4D seismic technology for monitoring the behavior of fluid motion and pressure variation in the Brazilian presalt reservoirs.

Abstract In January 2011, 3D at Depth was awarded a RPSEA contract to bring high-resolution three-dimensional (3D) laser imaging technology from the lab into an underwater environment for the oil and gas industry. Throughout the project, CDL Inc. provided expert engineering support and materials to marinize the system. Thus far the project has included design of the core technology for reliable operation in a deep-water environment; pool testing; reliability testing; integration with a work-class ROV; demonstration in a ROV test tank; and turbidity testing. Open water testing is to commence in the first half of 2013. 3D laser imaging is a powerful data collection system that provides 3-D information for a specific area of interest. It is the predominate technology for terrestrial survey, construction, as-built analysis, and large-scale retro-fits. The 3D laser imaging market is a mature multi-billion dollar industry with an eco-system of software, expertise, and best practices. Developing the technology to provide high-definition subsea laser imaging enables the deep water industry to use the current state of the art in 3D metrology and related best practices developed for the terrestrial market. This paper builds on last year's paper (OTC 23006-PP) and will discuss updates to the system and demonstrations that have occurred over the last year. Top of the line terrestrial laser scanners produce cm spatial and range accuracy at up to one- hundred meters range. Due to the absorption of water, realizable deep-water systems are limited to tens of meters range depending on the target and water conditions. To our knowledge, this is the first time millimeter class measurement accuracy will be demonstrated at greater than 8m range for an underwater laser system mounted to a ROV. This technology is essential for improving the safety and reliability of deep water assets. The lack of timely and accurate survey-quality 3D measurements poses an integrity management challenge for such assets. A lack of accurate data results in either higher risks or higher costs to build and maintain environmentally safe production and product transportation systems. The speed and precision of the technology developed by this project reduces operating costs for underwater inspection, maintenance, and repair; reduces environmental risk through more accurate inspection; significantly improves construction practices and quality / reliability; reduces risks to high value assets; and provides rapid access to sharable survey-quality as-built data before, during and after construction.

Abstract The soaring cost of drilling in deep-water environments leads to a strong demand for high-quality interpretable images and associated models, both products of seismic imaging, in many basins around the world. Anisotropic models more closely represent the real earth's properties. Using them in migration increases our ability to create accurate images. Overall, this allows for more reliable inversion, interpretation, and drilling decisions. In addition, anisotropic imaging allows us to realize fully the potential of new data types (e.g., wide-azimuth and long-offsets towed-streamer data) and to incorporate systematically our understanding of the geology, the available rock physics and geomechanics information, and borehole data into the model building process. We discuss an anisotropic model building workflow that is easily adaptable to any geologic environment, data type, objectives, or available non-seismic information. We report successful imaging strategies made possible by this workflow and demonstrate the improved results with examples from North America and West Africa. Introduction Advances in seismic imaging are, arguably, the most important element in the rising success of deep-water exploration and development because they reduce interpretation and drilling risk to acceptable levels. Historically, anisotropic imaging was applied only on smaller projects in mature fields with abundant well data. In recent years, the demand for high-quality pre-salt and subsalt images made anisotropic depth imaging with vertical transverse isotropic (VTI) and tilted transverse isotropic (TTI) models the dominant industry practice, even for large-scale exploration projects in areas of limited well control, i.e., the majority of the deep-water basins around the world. In parallel, new data types (wide- and full-azimuth towed-streamer) were introduced and more advanced demultiple, migration, and inversion algorithms became available. Figure 1 illustrates the cumulative effect of all these improvements, comparing isotropic imaging with 2006 narrow-azimuth (NAZ) data with a VTI imaging result in the same area using 2011 wide-azimuth (WAZ) data. The much-improved and detailed velocity model follows the geology closely (Figure 1 b) and naturally translates into an image with better focusing, better event continuity, less reflector distortion, and more easily interpretable events at depths more than 30,000 ft below the autochthonous salt. In complex geologic situations, the improved images resulting from well-designed anisotropic imaging carry potential beyond that of typical structural and stratigraphic interpretation. In cases with thoughtful conditioning of the migrated amplitude data, careful calibration of well and seismic data, validation of amplitude fidelity, and preparation of appropriate background trend models, quantitative interpretation methods can be applied in situations previously thought to be off limits for quantitative work (Wagner et al., 2012). In addition, high-quality velocity models obtained during anisotropic imaging allow quantification of structural uncertainty for volumetric analysis (Osypov et al., 2011). Through such approaches, be it subsalt or pre-salt, reservoir development in deepwater environments can greatly benefit from recent advances in imaging.

Abstract Deepwater oil and gas development projects are extremely challenging. Specific factors contributing to deepwater subsurface characterization challenges include: limited well count, large variation in gross rock volume (GRV) estimates of low relief structures produced by even minor depth uncertainty, and complex overburdens (e.g., complex allochthonous salt). In response to these challenges, we conducted a multi-organization depth uncertainty analysis over the St. Malo subsalt, Lower Tertiary development in deepwater Gulf of Mexico. The project applied the Quantitative Uncertainty Analysis (QUA) method (Osypov et al., 2008). QUA is a linearized Bayesian velocity model (and subsequent depth) uncertainty analysis process sampling a set of anisotropic tomographic models. Bayesian methods require a prior model, which is a quantitative representation of our current subsurface understanding. Those familiar with Bayesian methods (e.g., from geostatistical reservoir characterization) know the importance and impact of properly specifying this prior model. To specify this prior we integrated information from various subsurface disciplines (geophysics, geology, drilling). The depth uncertainty estimates that were obtained are being used in building the next generation static model for St. Malo. Subsurface setting and reference imaging A collaborative, multi-organization depth uncertainty analysis was conducted (involving two E&P companies and a geophysical contractor) over the St. Malo subsalt, Lower Tertiary development in deepwater Gulf of Mexico, see Figure 1. The range of water depths in the St. Malo area is approximately 6,500 - 7,400 ft. The St. Malo structure is a 4-way closure with the top of the shallowest reservoir between 27,000 and 29,000 ft. This structure lies completely beneath a fairly tabular and " well behaved" allochthonous salt body, which has maximum thickness of approximately 11,000 ft. In terms of subsalt seismic imaging, St. Malo is easily one of the very best imaged structures in operator's deepwater Gulf of Mexico portfolio. It is also arguable that it is one of the best imaged subsalt structures anywhere in the deepwater Gulf of Mexico, which made it an excellent candidate for the first subsalt application of the Quantitative Uncertainty Analysis (QUA) method/workflow. QUA is a linearized Bayesian velocity (and subsequent depth) uncertainty analysis process, which assumes that both the prior distribution and the likelihood function follow multi-dimensional Gaussian distributions, see Osypov et al. (2008) and Osypov et al. (2011) for more details. Lewis and Hoelting (2012) describe a completely different approach to a similar velocity and depth uncertainty problem without salt in the overburden (their method is based on a production anisotropic MVA workflow used by the operator, see Neal et al. (2009)). The mean of the prior distribution is the " current" transversely isotropic (TI) imaging model, consisting of v0, d, and e (Thomsen, 1986). For this imaging model the symmetry axis is vertical (i.e., the imaging velocity model used as the reference model for the linearized QUA analysis at St. Malo is VTI).

Abstract Geophysical imaging and subsurface characterization for offshore petroleumexploration and reservoir characterization face increasingly demandingrequirements for reliability and for providing increased information about theearth's subsurface. New methods for data acquisition, data processing andsimultaneous analysis of multiple types of geophysical datasets (e.g. seismic, EM, gravity) are helping to meet these challenges but there is need to testthese methods and to quantify their robustness. Testing and evaluation of newmethods can be done using simulated benchmark datasets provided the simulationsare calculated using realistic models and that the simulation methodology iswell validated. The benchmark datasets must not only be reliably calculated butthey must be sufficiently large to mimic state-of-the-art fieldacquisitions. The SEG Advanced Modeling Project (SEAM), using funding provided by theResearch Partnership to Secure Energy for America (RPSEA), has developed amodel for a deepwater region that contains a major salt body and severalpetroleum reservoirs located around and beneath the salt. Constructing andconducting geophysical simulations on the model is a challenge for currenthigh-performance computing technology. A suite of geophysical simulations isbeing conducted on the model including acoustic-wave, Tilted TransverseIsotropic acoustic, Gravity, Controlled Source Electromagnetic, Magnetotelluricand Elastic. Geophysicists are actively using these datasets to facilitatetheir development and testing of new algorithms and acquisition schemes forbetter subsurface characterization. The access to large multidisciplinarydatasets calculated on a single realistic model developed for a deepwaterregion like the Gulf of Mexico has long been desired to allow testing andbenchmarking of geophysical techniques, testing of new data acquisitionschemes, and assessing the value of multi-disciplinary inversion approaches.SEAM is seeking to provide these datasets for the geophysical community. Introduction Geophysical imaging continues to undergo transformation as new data acquisitionand processing schemes allow increasingly complex regions of the earth's crustto be imaged with better and better resolution. Advances from ray-basedmigration methods to one-way wave propagation migration and now reverse timemigration have been made possible by the availability of faster computers thathave sufficient memory to hold large models that the methods require forsuccessful application. Advances in data acquisition have provided an enormousincrease in the amount and quality of data that are available to input into thenew imaging schemes. The ability to implement imaging approaches that are basedon more than the isotropic acoustic velocity of the earth have led tosignificant improvements in image quality and the type of information that canbe obtained from images. For example, Controlled-Source Electromagnetic (CSEM)data have been found to provide valuable information not only when usedindependently of other data but also have recently been found to add tremendousvalue to interpretation when used in combination with seismic data. The recentuse of anisotropic earth models that have not only a vertical axis of symmetry, so-called vertical transverse isotropy or VTI, but that that now have aspatially-varying non-vertical axis of symmetry (Tilter Transverse Isotropy, TTI) have led to better images of complex regions like the Gulf of Mexico andprovide the opportunity to provide constraints on geomechanical models of theregion.

Abstract In January 2011, 3D at Depth was awarded a RPSEA contract to bringhigh-resolution three-dimensional (3D) laser imaging technology from the labinto an underwater environment for the oil and gas industry. During theproject, CDL Inc. provided expert engineering support and materials to marinizethe system. The project included two underwater trials which demonstrated thefeasibility of utilizing high resolution laser detection and ranging (LADAR) ina subsea environment. 3D laser imaging is a powerful data collection system that provides 3-Dinformation for a specific area of interest. It is the predominate technologyfor terrestrial survey, construction, as-built analysis, and large-scaleretro-fits. The 3D laser imaging market is a mature multi-billion dollarindustry with an eco-system of software, expertise, and best practices. Developing the technology to provide high-definition subsea laser imagingenables the deep water industry to use the current state of the art in 3Dmetrology and related best practices developed for the terrestrialmarket. This paper discusses some of the theory behind subsea laser imaging andcompares this theory to the first set of underwater tests in a pool. Terrestrial laser scanners commonly produce centimeter spatial and rangeaccuracy at several hundred meter range. Due to the absorption of water, realizable deepwater systems are limited to tens of meters range depending onthe target and water conditions. To our knowledge, this is the first timesub-centimeter accuracy at greater than 6m range is demonstrated for anunderwater laser system. This technology is essential for better management of deep water assets. Thelack of timely and accurate survey-quality 3D measurements poses an integritymanagement challenge for such assets. A lack of accurate data results in eitherhigher risks or higher costs to build and maintain environmentally safeproduction and product transportation systems. The speed and precision of thetechnology developed by this project reduces operating costs for underwaterinspection, maintenance, and repair; reduces environmental risk through moreaccurate inspection; significantly improves construction practices and quality/ reliability; reduces risks to high value assets; and provides rapid access tosharable survey-quality as-built data before, during and afterconstruction.