The Society of Exploration Geophysicists (SEG) will hold its annual meeting and exhibition Oct. 18 to 21 in Dallas. During this time participants will have the opportunity to view more than 1,100 technical presentations ranging in topics from new frontiers in exploration to practical applications. The exhibition will feature a variety of companies showcasing the latest exploration technologies.

Some of the highlights of the show include the opening session and presidential address, the annual Challenge Bowl, networking events for students and women, and the Applied Science education program. This year’s program will feature Shaunna Morrison, a member of the NASA Mars Science Laboratory, who will discuss “Assessing the Red Planet’s habitability using the Rover Curiosity.”

In this special report E&P has highlighted some of the latest products and technologies to be shown at the SEG Annual Meeting and looks at how they will benefit companies in their ongoing search for new reserves.

The copy herein is contributed from service companies and does not reflect the opinions of Hart Energy.

Anisotropic inversion aids well planning in fractured reservoirs

At SEG 2016 CGG will be highlighting the latest releases across its GeoSoftware reservoir characterization portfolio and how their integration of multidisciplinary workflows helps overcome the most complex subsurface challenges in all types of reservoirs, including those that are naturally fractured. Better identification of fractures, differential stress and reservoir architecture is essential for effective well design and optimum production.

By revealing essential reservoir facies and rock property information, a new anisotropic inversion product within GeoSoftware’s Jason portfolio improves characterization of reservoirs with significant anisotropy and realizes the full value of azimuthal seismic data. The power of azimuth- based amplitude vs. offset inversion is used to make direct measurements of reservoir anisotropy. A dedicated analysis application provides information on critical parameters: anisotropy magnitude and direction, fracture density, and rock weaknesses, all calibrated to well control.

In shales a proper understanding of local anisotropy is critical in designing any well program. Engineers must ensure that horizontal wells are drilled along the directions of minimum local stress to obtain the best fracturing results. The outcomes of fracturing are better predicted when there is an understanding of local rock brittleness and fracture density.

In heavy oil applications reservoir caprock competency is important to avoid the catastrophic effects of escaping steam. Anisotropy-corrected density estimates from inversions also are required to define the lateral and vertical extends of bitumen-laden sandstones.

Workflows can be tailored to fit specific project needs. Companies can plug into their own preferred petrotechnical platform and processes as part of the seismic-to-simulation workflow.

Software aids in time-lapse interpretation

CoViz 4D from Dynamic Graphics Inc. is a software platform for advanced data integration. In particular, the newly enhanced Sim2Seis and 4D Geomechanics options in CoViz 9.0 provide a fully integrated and customizable environment for analysis of 4-D seismic datasets.

Time-lapse (4-D) seismic data are more widespread than ever before. Their potential to monitor conditions throughout the reservoir through time is being used to maximize produced oil while also reducing costs and risk. But however useful these data are, operators are understandably under increasing pressure to prove the value of 4-D volumes yet to be collected and to maximize the return on investment after acquisition. Typically this is accomplished through feasibility studies and seismic history-matching.

The true value of 4-D seismic data can only be maximized when fully integrated and analyzed alongside all other relevant subsurface data. These could be reservoir simulations, production data, well histories, microseismic, etc. So whereas feasibility studies and seismic history-matching have value, that value is compounded when these processes are analyzed in the context of other decision-critical information.

The CoViz 4D platform offers unparalleled levels of data integration in a dynamic, time-aware 4-D analytic environment. Vendor-neutral data importers for a wide range of formats can make imports as easy as drag-anddrop. World-class visualizations and animations can reveal hitherto unseen connections between diverse datasets. But most importantly, the CoViz Sim2Seis and 4D Geomechanics modules are fully integrated into this quantitative analytic environment for better, faster and more complete analysis of time-lapse seismic.

Electroseismic technology used as DHI

The idea of coupling electromagnetic and seismic energies for useful purposes dates back to the 1930s but was most recently enhanced by Exxon Mobil starting more than 30 years ago. Since then, ES Xplore was formed within the Hunt Energy Enterprises LLC, a venture startup incubator within Hunt Consolidated Inc., to provide E&P operators with better imaging technologies for identifying potential hydrocarbon deposits.

ES Xplore has developed a novel direct hydrocarbon indication technology for onshore fields. The key physical mechanism underlying ES Xplore’s technology is the ability of rocks to convert electromagnetic energy into seismic or acoustic energy and, in turn, convert seismic energy into electromagnetic energy. The significance of these conversions is their enhancement by the presence of very electrically resistive fluids such as hydrocarbons in the rock pore space and by more highly permeable rocks.

ES Xplore’s technology is a totally passive technique that utilizes the earth’s naturally produced electromagnetic fields to directly detect hydrocarbons. Unlike other electromagnetic techniques that measure the earth’s electrical resistivity on gross scales, ES Xplore relies on different rock physics and has spatial resolution on the order of seismic resolution. ES Xplore’s technology is the only passive exploration method that senses the electrical resistivity and permeability of a formation at seismic resolutions. ES Xplore holds eleven patents on the technology and has several additional patent applications pending.

Technique increases offshore confidence

A trial application of Ikon Science’s Ji-Fi to a known gas field correctly highlighted the presence of three thin gas sands at an existing well location. In contrast, industry- standard methods for inversion of seismic data failed to detect two of these three gas sands. Consequently, Murphy Exploration & Production, the operator, concluded that the new technology offered by Ji-Fi is indeed superior to existing methods for sample-based full-volume inversion of seismic data. A subsequent application of Ji-Fi to the seismic data at a proposed new well location on Murphy’s acreage in the Gulf of Mexico revealed the likely presence of oil-bearing sand. The Ji-Fi results were used to determine both the likelihood of an oil accumulation and the possible range of in-place volume. The increase (or potential decrease, in other cases) in confidence in the likelihood of finding oil and the range of volumes are critical in the decision-making process. Murphy balanced the costs of drilling with the expected reward of finding and producing oil. The well was subsequently drilled and found the expected oil sand. “Ji-Fi is rapidly becoming the new standard in inversion of seismic data within Murphy; there is no scientific argument not to take up this exiting capability,” said Norbert Van De Coevering with Murphy Exploration & Production. “Even if nothing is perfect, it is still far better than standard industry inversion techniques, which have substantial bias.”

Unified system for mixed mode seismic acquisition

With exploration activity today taking operators into more challenging environments, the need to acquire seismic data efficiently and often in mixed modes is a growing challenge. Variations in terrain where open and relatively unrestricted areas can be abruptly contrasted with villages, foothills, mountains, lakes and river deltas pose tremendous operational challenges for the seismic contractor.

When faced with such challenges, the list of acquisition equipment required to tackle the project can grow dramatically. Traditional heavy vibroseis sources might need to be complemented with lighter and more maneuverable vehicles, with shot hole or even weight drop equipment required for terrain outside the scope of vehicles. Cable-based systems might not have the flexibility required to cope with all the environmental challenges; hence, the need for additional cableless channels to complete the coverage might become apparent. And if marine sections also are encountered, specialized transition zone (TZ) equipment also might be required.

All of this becomes even more traumatic to the contractor if different manufacturers provide the equipment and multiple recording systems are installed, each with their own unique training requirements, data formats, workflows and quality control (QC) capabilities. This is one of the main reasons that INOVA Geophysical recently has released a new unified central system for seismic operations—iX1.

With iX1 contractors can mobilize G3i HD (a cabled recording system) with TZ capability, integrate with autonomous nodes (Hawk) and receive support for vibroseis and dynamite source types, all controlled from the same software platform. With a single platform delivering common data format to the client, regardless of whether the data are acquired by cable, nodal or TZ equipment and with common operational and QC workflows for ease of use and training, contractors working in these tough environments now have one less thing to worry about.

Module provides immediate data access

iGlass, a full subsurface life-cycle management solution that is a web-based ESRI GIS map interface from Katalyst Data Management, now has a new module for managing interpretation project archives called ProjectDataStor. Built on the PPDM 3.8 public data model, iGlass provides geoscientists direct access to their data when they need it rather than having to search through volumes of archives and wait for weeks or longer using traditional storage methods. Designed primarily for seismic, iGlass has since expanded to support multiple domains. Geoscientists can now view interpreted information such as filtered volumes, horizons, grids, faults, wells, etc., contained within technical projects in the same view as the field and original processed seismic data already in the system. Currently, the iGlass global data centers manage 618,000 unique seismic surveys covering 45 million km (28 million miles) of data for a total of 17.2 petabytes of storage. provides a convenient, budget-friendly alternative for licensing seismic data via ecommerce. Anyone can visit the site and search their area of interest to see what’s available for license, and many of the associated transactions can be easily handled online. The online marketplace has more than 3.5 million km (2.2 million miles) of 2-D data and 119,318 sq km (46,069 sq miles) of 3-D data available for license.

CSEM aids in EOR

EOR is always challenged by the knowledge of the oil/ water front. Only limited geophysical techniques have been applied. In addition to flood front movements, reservoir seal integrity has become an issue. Seal integrity is best addressed with microseismic, and waterflood front identification is best addressed with electromagnetics.

KMS studied the fluid imaging using electromagnetics and, after careful 3-D feasibility and noise tests, selected controlled-source electromagnetics (CSEM) in the time domain as the most sensitive method. From the 3-D modeling it was determined as a key requirement that borehole and surface data needed to be integrated by measuring between surface-to-borehole and also calibrated using conventional logs.

The world’s first EOR pilot with this method is presently running onshore Thailand based on several years of 3-D modeling-based design and fit-for-purpose hardware. The system is based on the KMS array electromagnetic receiver systems (KMS-820). It consists of unlimited nodes, each of which can be extended with a cabled 32-bit subacquisition controller. The company is presently adding shallow borehole 3-C microseismic/ electromagnetic receivers and has started the development of deep borehole receivers. Concurrent to this project, KMS is commercializing the first generation of deepwater microseismic/electromagnetic marine nodes that will allow the concept to be extended into deep water.

Getting Mohr from microseismic

Microseismic Inc. recently has extended its proprietary data analysis workflow to allow the accurate estimate of focal mechanisms for the majority of recorded microseismic events in any fracture monitoring project. This in situ analysis reveals the strike, dip and rake of the failure plane of the event, which in turn can be used to estimate two important reservoir parameters:

• The magnitude and direction of maximum horizontal stress (SHmax); and

• The minimum stimulation pressure for the activation of natural fractures at different orientations.

Both numerical simulations of hydraulic fracturing in naturally fractured reservoirs and microseismic observations of actual treatments demonstrate the impact of the horizontal stress anisotropy on the final stimulation pattern and the mechanical interaction between consecutive fractures. Horizontal stress anisotropy is defined as the difference between the magnitude of minimum (SHmin) and maximum horizontal stresses. Higher stress anisotropy promotes more planar fracture patterns that extend away from the injection point, while lower stress anisotropy leads to more fracture complexity closer to the injection point. Knowledge of the existing anisotropy prior to stimulation is key to the optimum design of well spacing and stage length. While the magnitude of SHmin can be determined using well test data (e.g., a mini-fracture test or diagnostic fracture injection test), there has not been an easy and reliable method to determine the magnitude of SHmax along horizontal wells. This new development fills this gap and provides a mathematical approach to the determination of local SHmax using microseismic field observations. Knowing the full stress tensor allows the required minimum stimulation pressure to activate natural fractures to be calculated assuming a Mohr-Coulomb failure criterion.

Fiber optics for shale

OptaSense Oilfield Services has released a distributed fiber-optic sensing (DFOS) system for shale reservoirs that provides vertical seismic profiling (VSP), hydraulic fracture profiling and production flow monitoring in real time from a single system.

Using distributed acoustic sensing technology, the DFOS system transforms a permanently installed fiber-optic cable into an array of distributed acoustic sensors that detects changes in temperature, stress and acoustics along the entire wellbore.

The system acts as a borehole seismic sensor array capable of acquiring 2-D, 3-D and 4-D VSP data in both vertical and horizontal wells. These data enhance the understanding of near-well and interwell structural integrity, rock mechanical properties, in situ stress and natural fractures, which is critical for profitable site selection, well positioning and fracture placement.

For optimal fracture completions, the DFOS system confirms the integrity, seating and placement of bridge plugs and perforation guns. It also monitors the distribution and placement of proppant and fluid in real time, allowing operators to optimize pumping schedules, prevent understimulated or overstimulated zones, adjust stage spacing and monitor cross-well communications.

With the DFOS system, users also can visualize inflow and axial flow at the perforation level for the life of the asset. This allows them to pinpoint underperforming clusters while monitoring the impact of production on the reservoir over time. And, unlike other production logging methods, the system enables repeat surveys and continuous monitoring without the need for well intervention. Visit or booth 2413 at SEG for more information.

Theater features exploration, development workflows

At SEG 2016 Paradigm will use its theater program to feature a series of high-definition workflows in support of strategic exploration and development in onshore North American basins and offshore deepwater basins.

In seismic processing and imaging the program will include a novel full-azimuth diffraction imaging product to recover low-energy faults, a well marker mis-tie tomography workflow for precision depthing, a time-variant broadband deghosting approach for upgrading legacy and modern offshore acquisitions and new solutions to improve the efficiency of geophysicists working with multiline 2-D projects.

In seismic interpretation the program will feature its flagship Interpretation suite running in a new application framework (Epic) designed to foster higher levels of usability and productivity. New workflows for quantitative seismic interpretation will be introduced, including prestack elastic inversion with stochastic refinement for thin bed evaluation and a new probabilistic lithofacies workflow that integrates rock typing, electrofacies models and seismic data for improved facies modeling.

In subsurface modeling Paradigm will demonstrate the application of its chronostratigraphic modeling product for simultaneous volumetric seismic interpretation and modeling. The application is designed to facilitate the interpretation correlation problem, recover stratigraphic features and resolve interpretation errors. The application also will be used to support unified geologic and velocity modeling activities.

Formation evaluation solutions will focus on geomechanics, shale analysis and integrated wellbore and seismic data-driven pore pressure solutions suitable for overpressure predictions in all types of basins and source conditions.

Special presentations will include reservoir-driven production optimization and a look at future directions.

New sensor provides improved images

Paulsson Inc. has developed a line of innovative all-optical- based seismic vector sensor technologies for high-resolution oil and gas reservoir characterization and monitoring. The development has been funded by the U.S. Department of Energy and the Research Partnership to Secure Energy for America since 2010. The ultrasensitive high-vector fidelity large-bandwidth high-temperature fiber-optic seismic sensors have been integrated into a borehole seismic system using an optical data transmission technology and have been successfully field-tested. The system is capable of long-term deployment at 30,000 psi and 300 C (572 F), so it can meet the most stringent requirements for well operations. In parallel, an optically based ultralarge hydrophone array technology has been developed that will for the first time allow cost-effective large-aperture 3-D vertical seismic profiles to be recorded in the deepwater Gulf of Mexico.

In several tests the fiber-optic seismic sensors have shown to have superior performance relative to stateof- the-art seismic sensors such as exploration-type coil geophones and high-performance accelerometers in terms of bandwidth, sensitivity and high-temperature performance. The lower noise floor, the flatter spectral response and the higher sensitivity of the new fiberoptic seismic sensor will allow higher resolution imaging and detailed reservoir characterization and monitoring.

To deploy the new vector sensor system, a drillpipe-based deployment system has been developed allowing the receiver array to be deployed in both vertical and horizontal wells, which is an operational requirement in shale oil and gas wells since many of the wells drilled for shale oil and gas are highly deviated or horizontal.

Integrating seismic imaging and inversion

For years processing, imaging and inversion have been undertaken by separate teams, often in different companies. However, such siloed workflows are inefficient and can lead to errors. Precision is required from the beginning to the end of the geophysical process. The only way to achieve this goal is with an integrated team, leading-edge software and technical innovations.

As a first step, Rock Solid Images integrated seismic imaging and inversion workflows to optimize the time to solution of a seismic characterization project while improving the quality of rock property prediction in depth by ensuring consistency throughout. The process was tested using a faulted model including both wet and pay scenarios. Synthetic seismic data were generated using full waveform anisotropic elastic simulation. The resulting data were migrated using a wavefront reconstruction Kirchhoff summation prestack depth migration (PSDM).

The resulting gathers were then inverted using a simultaneous elastic impedance inversion. Both velocities and surfaces were consistent through the imaging and inversion stages. The elastic attributes obtained were transformed to rock properties using a multiattribute rotation scheme and compared to the input model. The observed misfit between the input and predicted reservoir properties is small.

Results demonstrate that PSDM preserves the relative amplitude of the data, allowing rock properties to be robustly predicted and positioned in depth. The value of close integration of imaging and inversion is clear. Further studies will use integrated imaging and inversion to investigate the amplitude responses underneath layers such as basalt or salt with the aim of estimating reservoir properties in such challenging scenarios.

World’s first smart sensor is released

The world’s first smart seismic sensor product, Smart- Solo IG-16 Intelligent Seismic Sensor, has been released by SmartSolo Inc. Different from traditional seismic data acquisition systems that focus mainly on data transfer and storage methods, SmartSolo targets the root of seismic— sensors. The core of this smart sensor is DTCC’s DT-Solo high-sensitivity geophone available in 5-Hz and 10-Hz options. The smart sensor knows its location (line and station number) and timing and records seismic reflections with the highest fidelity.

Each sensor weights about 2 lb including internal lithium batteries that can support recording up to 50 days. The SmartSolo has no external connectors exposed during normal field use operations. This greatly improves reliability.

SmartSolo mobile apps (iOS and Android) can be used for spread layout, navigation, technical support, training and inventory management. With the help of mobile Internet technologies, clients are able to get the highest efficiency at the lowest possible equipment and operational costs.

The target market for smart seismic sensors is ultrascale, high-density and high-resolution seismic projects. Only extremely cost-effective equipment such as SmartSolo can make such projects possible.

Source reduces stress on marine life

The eSource from Teledyne is the first bandwidthcontrolled seismic source designed to limit unwanted energy in the frequency range used by marine life. The eSource can be tuned to three levels that reduce high-frequency energy while retaining output that is crucial to seismic exploration, depending on regulatory and geological requirements.

Teledyne also will be showcasing other products at SEG, including:

RTS SmartSource Gun Controller: The SmartSource is the next generation in digital marine seismic source control. With a simplified user interface and troubleshooting process, the system is now more reliable and functional than ever. The new design enables the most modern seismic source array and includes new controller and power supply units and a new solenoid control valve assembly with integrated real-time pressure, depth and continuous near-field hydrophone monitoring. The SmartSource works with existing sources, minimizing new equipment.

RTS/AG 24 Bit Hydrophone: The rugged, encapsulated Smart Phone D, an integrated 24-bit digital hydrophone, sets new standards in near-field measurements. Digitizing at the sensor element provides the lowest noise interconnect, eliminating the issues of long signal lines and cross-coupling while providing unprecedented signature fidelity. The unique straight-to-digital design allows maximum flexibility in umbilical design by providing digital clarity regardless of length.

Wireless data acquisition system eliminates cabling

Wireless Seismic Inc. is releasing its RT System 2—a cablefree seismic data acquisition system featuring a high-bandwidth radio network that handles the real-time data transmission associated with the thousands of recording units required by modern 3-D surveys. Seismic contractors get the operational benefits of eliminating cables but no longer need to operate “blind” and deal with the significant overhead of manual data collection and transcription associated with autonomous nodal systems.

Wireless remote units (WRUs) placed at each recording location have a dual function: digitizing reflected signals generated below the surface and relaying these data along the line of WRUs to the central recorder. Since the radios only communicate across the interval distance of adjacent WRUs, modest battery power (from small custom lithium-ion batteries) efficiently supports hundreds of WRUs in a single “line” during deployment. Test results, battery capacity, data quality and other key facts are relayed back to the central recording system in real time; recorded data are safe from theft or failure, and the system operator can validate data quality and data integrity without delay.

The RT System 2 ensures that the seismic data are recorded properly via continuous quality control. The system requires significantly less crew personnel than a cabled system or autonomous nodal system. Because it is lightweight, the number of vehicles on the recording crew is substantially reduced, thus saving significant fuel costs and further reducing personnel costs.