News Article | May 2, 2017
This report studies the global Exploration and Production (E&P) Software market, analyzes and researches the Exploration and Production (E&P) Software development status and forecast in United States, EU, Japan, China, India and Southeast Asia. This report focuses on the top players in global market, like Market segment by Type, Exploration and Production (E&P) Software can be split into Premise Software Cloud-based Software Managed Software Market segment by Application, Exploration and Production (E&P) Software can be split into Oil & Gas Mine & Metallurgy Other Global Exploration and Production (E&P) Software Market Size, Status and Forecast 2022 1 Industry Overview of Exploration and Production (E&P) Software 1.1 Exploration and Production (E&P) Software Market Overview 1.1.1 Exploration and Production (E&P) Software Product Scope 1.1.2 Market Status and Outlook 1.2 Global Exploration and Production (E&P) Software Market Size and Analysis by Regions 1.2.1 United States 1.2.2 EU 1.2.3 Japan 1.2.4 China 1.2.5 India 1.2.6 Southeast Asia 1.3 Exploration and Production (E&P) Software Market by Type 1.3.1 Premise Software 1.3.2 Cloud-based Software 1.3.3 Managed Software 1.4 Exploration and Production (E&P) Software Market by End Users/Application 1.4.1 Oil & Gas 1.4.2 Mine & Metallurgy 1.4.3 Other 2 Global Exploration and Production (E&P) Software Competition Analysis by Players 2.1 Exploration and Production (E&P) Software Market Size (Value) by Players (2016 and 2017) 2.2 Competitive Status and Trend 2.2.1 Market Concentration Rate 2.2.2 Product/Service Differences 2.2.3 New Entrants 2.2.4 The Technology Trends in Future 3 Company (Top Players) Profiles 3.1 Paradigm 3.1.1 Company Profile 3.1.2 Main Business/Business Overview 3.1.3 Products, Services and Solutions 3.1.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.1.5 Recent Developments 3.2 Schlumberger 3.2.1 Company Profile 3.2.2 Main Business/Business Overview 3.2.3 Products, Services and Solutions 3.2.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.2.5 Recent Developments 3.3 ION Geophysical 3.3.1 Company Profile 3.3.2 Main Business/Business Overview 3.3.3 Products, Services and Solutions 3.3.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.3.5 Recent Developments 3.4 ETL Solutions 3.4.1 Company Profile 3.4.2 Main Business/Business Overview 3.4.3 Products, Services and Solutions 3.4.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.4.5 Recent Developments 3.5 Interactive Network Technologies 3.5.1 Company Profile 3.5.2 Main Business/Business Overview 3.5.3 Products, Services and Solutions 3.5.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.5.5 Recent Developments 3.6 Quorum 3.6.1 Company Profile 3.6.2 Main Business/Business Overview 3.6.3 Products, Services and Solutions 3.6.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.6.5 Recent Developments 3.7 Halliburton 3.7.1 Company Profile 3.7.2 Main Business/Business Overview 3.7.3 Products, Services and Solutions 3.7.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.7.5 Recent Developments 3.8 Triple Point Technology 3.8.1 Company Profile 3.8.2 Main Business/Business Overview 3.8.3 Products, Services and Solutions 3.8.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.8.5 Recent Developments 3.9 FEI 3.9.1 Company Profile 3.9.2 Main Business/Business Overview 3.9.3 Products, Services and Solutions 3.9.4 Exploration and Production (E&P) Software Revenue (Value) (2012-2017) 3.9.5 Recent Developments 4 Global Exploration and Production (E&P) Software Market Size by Type and Application (2012-2017) 4.1 Global Exploration and Production (E&P) Software Market Size by Type (2012-2017) 4.2 Global Exploration and Production (E&P) Software Market Size by Application (2012-2017) 4.3 Potential Application of Exploration and Production (E&P) Software in Future 4.4 Top Consumer/End Users of Exploration and Production (E&P) Software For more information, please visit https://www.wiseguyreports.com/sample-request/1239077-global-exploration-and-production-e-p-software-market-size-status-and-forecast-2022
Hossain Z.,ION Geophysical
50th US Rock Mechanics / Geomechanics Symposium 2016 | Year: 2016
As indicated by Thomsen's landmark paper on seismic anisotropy, delta (8) can be positive or negative. Because of this, anisotropy may have an additive or subtractive effect on stress ratios, pore-pressure, tectonic stress and anisotropy gradient predictions for seismic based geomechanical characterization of conventional and unconventional reservoirs. Therefore, the objective of this study is to demonstrate the effect of Thomsen's 8 on stress anisotropy in complex hydrocarbon reservoirs. We provided the relations between vertical and horizontal stress as a function of 8 for orthorhombic media. Furthermore, we derived a mechanical definition of Thomsen's S to reveal when 8 is positive and when 8 is negative. Finally, we established a link between S, tectonic stress and anisotropy gradient. For conventional depleted reservoirs, we demonstrated how S can be negative because of small horizontal stress. We described that S is a potential parameter to monitor a dynamic reservoir where stress changes are related with production, injection, and compaction. For unconventional reservoirs, we established a link between Thomsen's delta and tectonic strains. We showed that in the absence of a layer anisotropy parameter, tectonic stress and the anisotropy gradient can be calculated from the upper bound and lower bound of Thomsen's 8. We used the anisotropy gradient to describe fracture density and tectonic stress to define whether fractures are open or closed. Hence, combining the anisotropy gradient with tectonic stress can be used to define the optimal conditions for hydraulic fracturing for unconventional reservoir characterization. Copyright 2016 ARMA.
News Article | November 24, 2016
Dublin and London - November 24, 2016 - Providence Resources P.l.c. (PVR LN, PRP ID), the Irish based Oil and Gas Exploration Company, today provides an update on the Frontier Exploration Licence ("FEL") 2/14 drilling project, which lies in c. 2,250 metre water depth in the southern Porcupine Basin and is located c. 220 kilometres off the south west coast of Ireland. The licence is operated by Providence Resources P.l.c. ("Providence") (80%) on behalf of its partner Sosina Exploration Limited ("Sosina") (20%), (collectively referred to the "JV Partners"). FEL 2/14 contains the Paleocene "Druid" and the Lower Cretaceous "Drombeg" exploration prospects. On behalf of the JV Partners, Providence has signed a contract for the provision of a Harsh Environment Deepwater Mobile Drilling Unit (the "Contract") with Stena Drillmax Ice Limited ("Stena"), a wholly owned subsidiary of Stena International S.A., for the Stena IceMAX drill-ship. The Stena IceMAX is a modern harsh environment dual derrick drill-ship designed to operate in water depths of up to c. 3 km. The Contract provides for one firm well, plus an additional option, which is electable at the discretion of the JV Partners for the drilling of a second follow-on well. The operational rig rate is $185,000 per day. In addition to the finalisation of the Contract, other key service contracts are now being prepared for the planned drilling operations. Based on the latest project timeline and, subject to standard regulatory approvals and consents, the 53/6-A exploration well is currently planned to spud in June 2017. "We are delighted to have signed this rig contract with Stena. Our previous exploration collaboration project with Schlumberger highlighted the significant hydrocarbon potential of FEL 2/14 which we will now be evaluating using the high specification Stena IceMAX drill-ship. The signing of this rig contract is a major milestone in the project plan to enable the drilling of this high impact exploration well during summer 2017." Providence Resources is an Irish based Oil and Gas Exploration Company with a portfolio of appraisal and exploration assets located offshore Ireland. Providence's shares are quoted on AIM in London and the ESM in Dublin. Stena Drilling is one of the world's leading companies in the development, construction and operation of offshore drilling rigs and drill-ships. Stena's fleet consists of four ultra-deep-water drill-ships and three semi-submersible rigs. Stena IceMAX is the world's first dynamically positioned, dual mast ice-class drillship. The Stena IceMAX is a Harsh Environment DP Class 3 drillship capable of drilling in water depths up to 10,000ft. The IceMAX has on-board 2 x BOP's, each 18 3/4" x 15,000psi Cameron "TL" BOP c/w ST Locks, and uses Cameron Load King riser. The vessel was delivered in April 2012. During the initial pre-FEL 2/14 authorisation phase (Licensing Option 11/9 - 2011 through 2013), Providence and Sosina identified two large vertically stacked Paleocene ('Druid') and Lower Cretaceous ('Drombeg') fan systems with notable Class II amplitude versus offset ("AVO") anomalies primarily from 2D seismic data acquired in 2008. Providence and Sosina subsequently agreed to underwrite a multi-client 3D seismic survey over the area. This 3D survey was acquired by Polarcus in the summer of 2014 and subsequently processed by ION Geophysical in 2014/15. In September 2015, Providence and Sosina entered into a Strategic Exploration Collaboration Project with Schlumberger. In April 2016, the main results of this Project were announced: · Two fans located c. 1,750 m BML and structurally up-dip from a potential significant fluid escape feature from the underlying pre-Cretaceous Diablo Ridge · Cumulative in-place un-risked prospective resources of 3.180 BBO (PMean) o Fan 1 - 984 MMBO (PMean) o Fan 2 - 2,196 MMBO (PMean) · Pre-stack seismic inversion and regional rock physics analysis shows Druid is consistent with a highly porous (30%) and high net-gross, light oil-filled sandstone reservoir system up to 85 metres thick ·A depth conformant Class II AVO anomaly is present and synthetic forward modelling of an oil-water contact correlates with the observed seismic response ·Spectral decomposition, seismic compactional drape and mounding are reflective of a large sand-rich submarine fan system with no significant internal faulting and clear demonstration of an up-dip trap mechanism ·Geomechanical analysis using regional well and high resolution seismic velocity data indicates that Druid is normally pressured and the top seal is intact ·Located c. 2,750 m BML and structurally up-dip from a potential significant fluid escape feature from the underlying pre-Cretaceous Diablo Ridge ·In-place un-risked prospective resource of 1.915 BBO (PMean) · Pre-stack seismic inversion and regional rock physics analysis shows Drombeg is consistent with a highly porous (20%), light oil-filled sandstone reservoir system up to 45 metres thick ·A depth conformant Class II AVO anomaly is present and spectral decomposition is reflective of a large sand-rich submarine fan system with no significant internal faulting, and supports an up-dip trap mechanism ·Geomechanical analysis using regional well and high resolution seismic velocity data indicates that Drombeg is over-pressured with an intact top seal This announcement has been reviewed by Dr John O'Sullivan, Technical Director, Providence Resources P.l.c. John is a geology graduate of University College, Cork and holds a Masters in Applied Geophysics from the National University of Ireland, Galway. He also holds a Masters in Technology Management from the Smurfit Graduate School of Business at University College Dublin and a doctorate in Geology from Trinity College Dublin. John is a Chartered Geologist and a Fellow of the Geological Society of London. He is also a member of the Petroleum Exploration Society of Great Britain, the Society of Petroleum Engineers and the Geophysical Association of Ireland. John has more than 25 years of experience in the oil and gas exploration and production industry having previously worked with both Mobil and Marathon Oil. John is a qualified person as defined in the guidance note for Mining Oil & Gas Companies, March 2006 of the London Stock Exchange. Definitions in this press release are consistent with SPE guidelines. SPE/WPC/AAPG/SPEE Petroleum Resource Management System 2007 has been used in preparing this announcement.
Leveille J.P.,ION Geophysical |
Jones I.F.,ION GX Technology |
Zhou Z.-Z.,ION GX Technology |
Wang B.,TGS Inc |
Liu F.,Hess Corporation
Geophysics | Year: 2011
The field of subsalt imaging has evolved rapidly in the last decade, thanks in part to the availability of low cost massive computing infrastructure, and also to the development of new seismic acquisition techniques that try to mitigate the problems caused by the presence of salt. This paper serves as an introduction to the special Geophysics section on Subsalt Imaging for E&P. The purpose of the special section is to bring together practitioners of subsalt imaging in the wider sense, i.e., not only algorithm developers, but also the interpretation community that utilizes the latest technology to carry out subsalt exploration and development. The purpose of the paper is in many ways pedagogical and historical. We address the question of what subsalt imaging is and discuss the physics of the subsalt imaging problem, especially the illumination issue. After a discussion of the problem, we then give a review of the main algorithms that have been developed and implemented within the last decade, namely Kirchhoff and Beam imaging, one-way wavefield extrapolation methods and the full two-way reverse time migration. This review is not meant to be exhaustive, and is qualitative to make it accessible to a wide audience. For each method and algorithm we highlight the benefits and the weaknesses. We then address the imaging conditions that are a fundamental part of each imaging algorithm. While we dive into more technical detail, the section should still be accessible to a wide audience. Gathers of various sorts are introduced and their usage explained. Model building and velocity update strategies and tools are presented next. Finally, the last section shows a few results from specific algorithms. The latest techniques such as waveform inversion or the "dirty salt" techniques will not be covered, as they will be elaborated upon by other authors in the special section. With the massive effort that the industry has devoted to this field, much remains to be done to give interpreters the accurate detailed images of the subsurface that are needed. In that sense the salt is still winning, although the next decade will most likely change this situation. © 2011 Society of Exploration Geophysicists.
Liu F.,Hess Corporation |
Zhang G.,CAS Academy of Mathematics and Systems Science |
Morton S.A.,Hess Corporation |
Leveille J.P.,ION Geophysical
Geophysics | Year: 2011
Reverse-time migration (RTM) exhibits great superiority over other imaging algorithms in handling steeply dipping structures and complicated velocity models. However, low-frequency, high-amplitude noises commonly seen in a typical RTM image have been one of the major concerns because they can seriously contaminate the signals in the image if they are not handled properly. We propose a new imaging condition to effectively and efficiently eliminate these specific noises from the image. The method works by first decomposing the source and receiver wavefields to their one-way propagation components, followed by applying a correlation-based imaging condition to the appropriate combinations of the decomposed wavefields. We first give the physical explanation of the principle of such noises in the conventional RTM image. Then we provide the detailed mathematical theory for the new imaging condition. Finally, we propose an efficient scheme for its numerical implementation. It replaces the computationally intensive decomposition with the cost-effective Hilbert transform, which significantly improves the efficiency of the imaging condition. Applications to various synthetic and real data sets demonstrate that this new imaging condition can effectively remove the undesired low-frequency noises in the image. © 2011 Society of Exploration Geophysicists.
Haney M.M.,Alaska Volcano Observatory |
Douma H.,ION Geophysical
Leading Edge (Tulsa, OK) | Year: 2012
Within reflection seismology, surface waves or ground roll, are often considered a form of unwanted source-generated noise. Unlike body waves, surface waves propagate exclusively in the lateral direction and are virtually insensitive to structure deeper than one wavelength. For a nominal frequency of 5 Hz and phase velocity of 500 m/s, this means that a surface wave of the Rayleigh or Love type only feels the upper 100 m of the subsurface. As a result, surface waves cannot be used for imaging deep reflectors; however, they can be used to estimate near-surface properties (Xia et al., 1999; Ross et al., 2008), in particular the shear-wave velocity. Knowledge of near-surface velocity structure in turn can be used to estimate shear-wave statics in reflection seismology. Estimating statics in the presence of laterally varying structure (i.e., obtaining the long-wavelength static component) can be challenging. © 2012 Society of Exploration Geophysicists.
Vasconcelos I.,University of Edinburgh |
Sava P.,Colorado School of Mines |
Douma H.,ION Geophysical
Geophysics | Year: 2010
Wave-equation, finite-frequency imaging and inversion still face many challenges in addressing the inversion of highly complex velocity models as well as in dealing with nonlinear imaging (e.g., migration of multiples, amplitude-preserving migration). Extended images (EIs) are particularly important for designing image-domain objective functions aimed at addressing standing issues in seismic imaging, such as two-way migration velocity inversion or imaging/inversion using multiples. General one- and two-way representations for scattered wavefields can describe and analyze EIs obtained in wave-equation imaging. We have developed a formulation that explicitly connects the wavefield correlations done in seismic imaging with the theory and practice of seismic interferometry. In light of this connection, we define EIs as locally scattered fields reconstructed by model-dependent, image-domain interferometry. Because they incorporate the same one- and two-way scattering representations usedfor seismic interferometry, the reciprocity-based EIs can in principle account for all possible nonlinear effects in the imaging process, i.e., migration of multiples and amplitude corrections. In this case, the practice of two-way imaging departs considerably from the one-way approach. We have studied the differences between these approaches in the context of nonlinear imaging, analyzing the differences in the wavefield extrapolation steps as well as in imposing the extended imaging conditions. When invoking single-scattering effects and ignoring amplitude effects in generating EIs, the one- and two-way approaches become essentially the same as those used in today's migration practice, with the straightforward addition of space and time lags in the correlation-based imaging condition. Our formal description of the EIs and the insight that they are scattered fields in the image domain may be useful in further development of imaging and inversion methods in the context of linear, migration-based velocity inversion or in more sophisticated image-domain nonlinear inverse scattering approaches. © 2010 Society of Exploration Geophysicists.
Jones I.,ION Geophysical
75th EAGE Conference and Exhibition Incorporating SPE EUROPEC 2013 | Year: 2013
The physical behaviour of most earth materials is fairly straightforward, both in terms of their deposition and subsequent deformation. Consequently, the geometries to be imaged and interpreted are likewise usually well understood. Salts, however, do not conform to the usual behaviours of earth materials due to the ductile nature of the material. Consequently, in both imaging and interpretation of salt province data, special care needs to be taken. In this work, we review various considerations for velocity model building, migration, and subsequent interpretation of complex salt bodies.
Jones I.F.,ION Geophysical
76th European Association of Geoscientists and Engineers Conference and Exhibition 2014: Experience the Energy - Incorporating SPE EUROPEC 2014 | Year: 2014
Conventional seismic data processing, whether it be pre-stack data conditioning or migration, is designed with the theory of P-wave reflected energy in-mind, for travel paths involving only a single reflection. Any energy propagating with other modes or travel paths will not be dealt with appropriately during conventional seismic data processing. It is primarily for this reason that we spend so much time preconditioning seismic data, so as to meet the assumptions of the subsequent migration. In this study, looking at shallow-water marine data from high velocity-contrast environments (such as found with basalt or carbonates), I assess the behaviour of some other classes seismic energy, when subjected to conventional processing, so as to better understand the anomalous events appearing in migrated CRP gathers and images, due to contamination of the data with remnant refraction and mode-converted energy.
Zhou Z.-Z.,ION Geophysical |
Howard M.,BHP Billiton |
Mifflin C.,BHP Billiton
Geophysics | Year: 2011
Various reverse time migration (RTM) angle gather generation techniques have been developed to address poor subsalt data quality and multiarrival induced problems in gathers from Kirchhoff migration. But these techniques introduce new problems, such as inaccuracies in 2D subsurface angle gathers and edge diffraction artifacts in 3D subsurface angle gathers. The unique rich-azimuth data set acquired over the Shenzi field in the Gulf of Mexico enabled the generally artifact-free generation of 3D subsurface angle gathers. Using this data set, we carried out suprasalt tomography and salt model building steps and then produced 3D angle gathers to update the subsalt velocity. We used tilted transverse isotropy RTM with extended image condition to generate full 3D subsurface offset domain common image gathers, which were subsequently converted to 3D angle gathers. The angle gathers were substacked along the subsurface azimuth axis into azimuth sectors. Residual moveout analysis was carried out, and ray-based tomography was used to update velocities. The updated velocity model resulted in improved imaging of the subsalt section. We also applied residual moveout and selective stacking to 3D angle gathers from the final migration to produce an optimized stack image. © 2011 Society of Exploration Geophysicists.