Relevant bibliographies by topics / Direct Hydrocarbon Indicators (DHIs)

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  2. Dissertations / Theses
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Academic literature on the topic 'Direct Hydrocarbon Indicators (DHIs)'

Author: Grafiati
Published: 4 June 2021
Last updated: 13 February 2022

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Journal articles on the topic "Direct Hydrocarbon Indicators (DHIs)"

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Clark, Virginia A. "The effect of oil under in‐situ conditions on the seismic properties of rocks." GEOPHYSICS 57, no. 7 (July 1992): 894–901. http://dx.doi.org/10.1190/1.1443302.

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Direct hydrocarbon indicators (DHIs) on seismic sections are commonly thought to be diagnostic only of gas. However, oil sands can also generate DHIs such as bright spots and flat events since oils under in‐situ conditions can contain large amounts of solution gas. This dissolved gas substantially decreases the velocity of sound and the density of the oils as compared to measurements of these properties at surface conditions. Hydrocarbon indicators caused by oil sands are investigated by first measuring the elastic properties of an oil as a function of gas‐oil ratio, next, calculating the elastic properties of additional oil compositions under in‐situ conditions using standard pressure‐volume‐temperature (PVT) measurements, and then calculating the compressional velocity in oil‐saturated rocks for several typical oils using Gaasmann’s equation. The potential for seismic anomalies caused by oil‐saturated rocks is higher than thought because the properties of oil under reservoir conditions can differ significantly from those of surface oils. Specifically: 1) The properties of oil depend on its composition: the higher the API gravity and the gas‐to‐oil ratio (GOR), the lower the density and velocity of sound (adiabatic bulk modulus) and the lower the velocity of a rock saturated with the oil. 2) Calculations of oil‐sand velocities using the in situ properties of oils show that areas having light oils and/or poorly consolidated rocks are the most likely areas in which to encounter oil DHIs. Since overpressured areas can have both poorly consolidated rocks and high GOR oils, they are especially prone to large oil responses.
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Omoja, U. C., and T. N. Obiekezie. "Application of 3D Seismic Attribute Analyses for Hydrocarbon Prospectivity in Uzot-Field, Onshore Niger Delta Basin, Nigeria." International Journal of Geophysics 2019 (January 14, 2019): 1–11. http://dx.doi.org/10.1155/2019/1706416.

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3D seismic interpretative study was carried out across the Uzot-field in the western Coastal Swamp Depobelt of the onshore Niger Delta Basin, Nigeria, with the aim to identify possible hydrocarbon leads and prospects away from the drilled zone, utilizing seismic amplitude attributes. The method employed in this study involved systematic picking of faults and mapping of horizons/reservoir tops across seismic volume and extraction of seismic attributes. Structural analysis indicates the presence of down-to-basin footwall and hanging wall faults associated with rollover anticlines and horst-block (back-to-back fault). Generated time and depth structural maps from three reservoir intervals (D3100, D5000, and D9000) revealed the presence of fault dependent closure across the field. Analyses of relevant seismic attributes such as root-mean-square (RMS) amplitude, maximum amplitude, average energy amplitude, average magnitude amplitude, maximum magnitude attribute, and standard deviation amplitude, which were applied on reservoir tops, revealed sections with bright spot anomalies. These amplitude anomalies served as direct hydrocarbon indicators (DHIs), unravelling the presence and possible hydrocarbon prospective zones. In addition, structural top maps show that booming amplitude is seen within the vicinity of fault closures, an indication that these hydrocarbon prospects are structurally controlled. Results from this study have shown that, away from currently producing zone at the central part of the field, additional leads and prospects exist, which could be further evaluated for hydrocarbon production.
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Lowry, D. C., R. J. Suttill, and R. J. Taylor. "ADVANCES IN RISKING EXPLORATION PROSPECTS." APPEA Journal 45, no. 1 (2005): 143. http://dx.doi.org/10.1071/aj04012.

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Assessment of prospect risk is a vital exploration activity, but technical literature on the subject shows few advances in methodologies in the last 20 years. Origin Energy has found that published procedures are not always adequate. Three perceived shortcomings are examined and techniques are proposed to overcome them.Cases where prospect risk is dependent on reserve size. Traditional methodologies assume the two are independent. This assumption is clearly inappropriate for, say, a prospect for which the success case value is based on the mapped closure, but which has suspect seal capacity that may limit the column height to something less than full-to-spill. A way forward is to build a variable risk array for a range of column heights and calculate the incremental risked NPV for each layer. The expected monetary value (EMV) is computed for a range of column heights based on the NPV of cumulative risked reserves;Cases where the estimation of chance of success (COS) based on traditional geological information needs to be combined with direct hydrocarbon indicators (DHIs) from seismic data. DHIs are not infallible indicators, however, and cannot be used to set the COS for elements such as charge to say 100%. Bayes’ Theorem can be used to combine the two sets of uncertain information.Cases where prospects are risked on very limited data. Traditional risking does not adequately incorporate the level of knowledge on which risk assessments are made. Inadequacies are identified in existing methodologies, but no simple and satisfactory solutions can be identified. We do suggest a way forward, however, for a related problem—testing the sensitivity of the EMV calculation for an exploration prospect for uncertainties in COS.
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Kidney, Robert L., Ronald S. Silver, and H. A. Hussein. "3-D Seismic Mapping and Amplitude Analysis: A Gulf of Mexico Case History." Energy Exploration & Exploitation 10, no. 4-5 (September 1992): 259–80. http://dx.doi.org/10.1177/014459879201000406.

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Utilization of 3-D seismic data and Direct Hydrocarbon Indicators led to the successful drilling of appraisal and development wells in the Gulf of Mexico block South Timbalier 198 (ST 198). These seismic technologies, which are routinely used by Oryx Energy Company, significantly reduced the time and cost to appraise the ST 198 discovery. Based on 2-D seismic mapping, a Pliocene Lower Buliminella (L BUL) prospect was drilled in ST 198. Although the expected reservoir was not found, an Upper Buliminella (U BUL) gas sandstone was encountered. An appraisal well of the U BUL interval confirmed this discovery. Following the drilling of these two wells, it became apparent that the structural complexities and the seismic amplitude anomalies of the area could not be adequately resolved using the 2-D seismic grid. A 3-D seismic survey was shot to delineate the discovery and evaluate the remaining potential of the South Timbalier Block 198 (ST 198). Direct Hydrocarbon Indicators (DHIs), which are seismic anomalies resulting from the hydrocarbon effect on rock properties, are generally expected from these age sands. While the 3-D survey shows a seismic amplitude anomaly associated with the U BUL reservoir, the areal extent of the seismic anomaly did not match the findings of the two wells. A DHI study was performed to determine if this inconsistency could be explained and if the amplitude anomaly could be used in the well planning. The two key steps which confirmed that this amplitude anomaly is a DHI were properly calibrating the seismic data to the well control and determining the theoretical seismic response of the gas sandstones. The DHI study along with the 3-D mapping led to the successful development of the ST 198 U BUL reservoir and to setting up a successful adjacent fault block play. Finally, 3-D mapping also identified a L BUL trap updip from the original L BUL prospect which resulted in a successful drilling effort.
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Hart, T., B. Mamuko, K. Mueller, C. Noll, T. Snow, and A. Zannetos. "IMPROVING OUR UNDERSTANDING OF GIPPSLAND BASIN GAS RESOURCES—AN INTEGRATED GEOSCIENCE AND RESERVOIR ENGINEERING APPROACH." APPEA Journal 46, no. 1 (2006): 47. http://dx.doi.org/10.1071/aj05003.

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The Barracouta and Marlin gas fields are located within the Gippsland Basin, offshore Australia, and have been on production for more than 36 years. Combined, these fields represent over 6.5 TCF of recoverable gas. Structurally the fields are relatively simple, but they are significantly warped in seismic two-way time by high velocity channels above the reservoir that make time to depth conversion and volumetric assessment difficult.Fundamental to management of these fields has been surveillance data and history matching based on simulation of detailed geologic models. In the late 90s, the observation was made that actual contact movement within the fields was lagging behind model predictions, suggesting that the fields were potentially larger than previously assessed.Results from the 3D seismic surveys acquired in Barracouta in 1999 and both fields in 2001 were used to help answer questions related to contact movement, resource size and remaining recoverable gas. Two significant outcomes from these surveys were the observation of double Direct Hydrocarbon Indicators (DHIs) across both fields, representing both the original and current gas-water contacts (OGWC and CGWC respectively), and mappable amplitude features related to depositional trends.The double DHIs were used to calculate contact movement and sweep uniformity. The original contact DHI was also used to assist in depth conversion. The position of shorelines and upper to lower delta plain boundaries were extracted from the seismic amplitude features to refine net-to-gross distribution.The interpreted 3D data are integrated with well logs and surveillance data to create detailed geologic models used for material balance simulation of reservoir performance. A good match was obtained between the model and field measured pressures and contact movement. Based on this work, the estimates of recoverable gas in the two fields were increased by 0.7 TCF, a 14% increase over the previous estimate.
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Sang, Liqin, Uwe Klein-Helmkamp, Andrew Cook, and Juan R. Jimenez. "A practical workflow using quantitative interpretation of seismic amplitudes to derisk infill wells in deepwater Gulf of Mexico: The Auger example." Leading Edge 38, no. 10 (October 2019): 754–61. http://dx.doi.org/10.1190/tle38100754.1.

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Seismic direct hydrocarbon indicators (DHIs) are routinely used in the identification of hydrocarbon reservoirs and in the positioning of drilling targets. Understanding seismic amplitude reliability and character, including amplitude variation with offset (AVO), is key to correct interpretation of the DHI and to enable confident assessment of the commercial viability of the reservoir targets. In many cases, our interpretation is impeded by limited availability of data that are often less than perfect. Here, we present a seismic quantitative interpretation (QI) workflow that made the best out of imperfect data and managed to successfully derisk a multiwell drilling campaign in the Auger and Andros basins in the deepwater Gulf of Mexico. Data challenges included azimuthal illumination effects caused by the presence of the Auger salt dome, sand thickness below tuning, and long-term production effects that are hard to quantify without dedicated time-lapse seismic. In addition, seismic vintages with varying acquisition geometries led to different QI predictions that further complicated the interpretation story. Given these challenges, we implemented an amplitude derisking workflow that combined ray-based illumination assessments and prestack data observations to guide selection of the optimal seismic data set(s) for QI analysis. This was followed by forward modeling to quantify the fluid saturation and sand thickness effects on seismic amplitude. Combined with structural geology analysis of the well targets, this workflow succeeded in significantly reducing the risk of the proposed opportunities. The work also highlighted potential pitfalls in AVO interpretation, including AVO inversion for the characterization of reservoirs near salt, while providing a workflow for prestack amplitude quality control prior to inversion. The workflow is adaptable to specific target conditions and can be executed in a time-efficient manner. It has been applied to multiple infill well opportunities, but for simplicity reasons here, we demonstrate the application on a single well target.
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Gregersen, Ulrik, Torben Bidstrup, Jørgen A. Bojesen-Koefoed, Flemming G. Christiansen, Finn Dalhoff, and Martin Sønderholm. "Petroleum systems and structures offshore central West Greenland: implications for hydrocarbon prospectivity." Geological Survey of Denmark and Greenland (GEUS) Bulletin 13 (October 12, 2007): 25–28. http://dx.doi.org/10.34194/geusb.v13.4968.

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A detailed geophysical mapping project has been carried out by the Geological Survey of Denmark and Greenland (GEUS) in the offshore region south-west and west of Disko and Nuussuaq, central West Greenland as part of the preparations for the Disko West Licensing Round in 2006 (Fig. 1). The main purpose of the study was to evaluate the prospectivity of this almost 100 000 km2 large region, and to increase knowledge of basin evolution and the structural development. Results of the work, including a new structural elements map of the region and highlights of particular interest for hydrocarbon exploration of this area, are summarised below. Evidence of live petroleum systems has been recognised in the onshore areas since the beginning of the 1990s when seeps of five different oil types were demonstrated (BojesenKoefoed et al. 1999). Oil seeps suggesting widely distributed marine source rocks of Mesozoic age are particularly promising for the exploration potential (Bojesen-Koefoed et al. 2004, 2007). Furthermore, possible DHIs (Direct Hydro carbon Indicators) such as gas-clouds, pock marks, bright spots and flat events have been interpreted in the offshore region (Skaarup et al. 2000; Gregersen & Bidstrup in press). The evaluation of the region (Fig. 1) is based on all public and proprietary seismic data together with public domainmag- netic and gravity data. The seismic data (a total of c. 28 000 line km) are tied to the two existing offshore exploration wells in the region (Hellefisk-1 and Ikermiut-1). The study also incorporates information on sediments and volcanic rocks from onshore Disko and Nuussuaq (Fig. 2). Ten seismic horizons ranging from ‘mid-Cretaceous’ to ‘Base Quaternary’ (Fig. 2) have been interpreted regionally. Large correlation distances to wells, varying data quality and a thick cover of basalt in the north-eastern part of the region, add uncertainty in the regional interpretation, especially for the deeper horizons such as the ‘mid-Cretaceous’ equivalent to Santonian sandstone interval drilled in Qulleq-1 far south. Based on the seismic interpretation (Fig. 3) structural elements maps, horizon-depth maps and isopach maps have been produced; these maps, together with general stratigraphic knowledge on potential reservoirs, seals and source rocks (Fig. 2), provide important information for discussions of critical play elements including kitchens and structures.The existence of many large structures combined with the evidence of live petroleum systems has spurred the recent major interest for hydrocarbon exploration in the region.
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Frederick, J. B., E. J. Davies, P. G. Smith, D. Spancers, and T. J. Williams. "EXPLORATION OPPORTUNITIES, EAST COAST BASIN, NEW ZEALAND." APPEA Journal 40, no. 1 (2000): 39. http://dx.doi.org/10.1071/aj99003.

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The Westech-Orion Joint Venture holds onshore Petroleum Exploration Permit 38329 and offshore PEPs 38325, 38326 and 38333 in the East Coast Basin, New Zealand. The Joint Venture holds 24,117 km2 covering Hawkes Bay and the Wairarapa shelf.The Westech-Orion Joint Venture has drilled six exploratory wells and five appraisal wells in the onshore East Coast Basin over a two year period. All wells encountered significant gas shows, with two wells discovering hydrocarbons in potentially commercial volumes. Each well was drilled on the crest of a seismically mapped structure, characterised by asymmetric folding over a northwest dipping thrust fault.Prior to this drilling program, the reservoir potential of the Wairoa area was inferred to be dominated by turbidite sandstones of the Tunanui and Makaretu formations (Mid-Late Miocene). The new wells show that the Mid Miocene and parts of the Early and Late Miocene pinch out across the 'Wairoa High'.One of the primary onshore reservoirs is the Kauhauroa Limestone (Early Miocene), a bryozoan-dominated, tightly packed and cemented limestone with dominantly fracture porosity. The other primary reservoir is the Tunanui Sandstone (Mid Miocene), which in well intersections to date comprises medium-thickly bedded sandstone, with net sand typically 40%. The sands have high lithic content, and are moderately sorted and subangular-subrounded.Abnormally high formation pressures were encountered in all wells, ranging up to 3,400 psi at 1,000 m. Crestal pressure gradients commonly exceed 70% of the lithostatic pressure gradient, despite the relative proximity to outcrop. The overpressure may reflect relatively young uplift of fossil pressures, with insufficient time for pressure equilibration within a generally overpressured system.The prospectivity of the area has been highgraded by recent maturation and reservoir studies in Hawkes Bay and by gas discoveries in Westech-Orion wells onshore northern Hawkes Bay. Maturation studies identified nine kitchen areas with oil migration commencing in the Late Miocene. Seismic stratigraphy and correlation with onshore wells identified offshore submarine fan deposits of Eocene, Early Miocene, Mid Miocene and Pliocene age.A 594 km2 exploration 3D seismic survey was acquired in Hawke Bay in April 1999, and 685 km of 2D seismic were acquired in March 2000. Preliminary interpretation of the 3D survey has yielded five prospects, each covering 20–90 km2. One prospect is a lowstand fan identified by stacked mounding and bidirectional downlap, correlated with the onshore Mid Miocene Tunanui Sandstone. High amplitude seismic events of Mid-Late Miocene ages are inferred to be pulses of submarine fan development, in places associated with direct hydrocarbon indicators (DHIs). High amplitude seismic events in the Pliocene include a package of high amplitude seismic reflectors interpreted as structurally trapped DHI truncated by a major unconformity.
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BUSBY, J. P., R. J. PEART, C. A. GREEN, R. D. OGILVY, and J. P. WILLIAMSON. "A SEARCH FOR DIRECT HYDROCARBON INDICATORS IN THE FORMBY AREA1." Geophysical Prospecting 39, no. 5 (July 1991): 691–710. http://dx.doi.org/10.1111/j.1365-2478.1991.tb00336.x.

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Rowi, V., A. Haris, and A. Riyanto. "Direct hydrocarbon indicator (DHI) pitfall assessment in prospecting pliocene globigerina biogenic gas play in “X structure”, Madura Strait, East Java Basin." IOP Conference Series: Earth and Environmental Science 481 (April 28, 2020): 012046. http://dx.doi.org/10.1088/1755-1315/481/1/012046.

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Dissertations / Theses on the topic "Direct Hydrocarbon Indicators (DHIs)"

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Lasisi, Ayodele Oluwatoyin. "Pore pressure prediction and direct hydrocarbon indicator: insight from the southern pletmos basin, offshore South Africa." Thesis, University of the Western Cape, 2014. http://hdl.handle.net/11394/4255.

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>Magister Scientiae - MSc
An accurate prediction of pore pressure is an essential in reducing the risk involved in a well or field life cycle. This has formed an integral part of routine work for exploration, development and exploitation team in the oil and gas industries. Several factors such as sediment compaction, overburden, lithology characteristic, hydrocarbon pressure and capillary entry pressure contribute significantly to the cause of overpressure. Hence, understanding the dynamics associated with the above factors will certainly reduce the risk involved in drilling and production. This study examined three deep water drilled wells GA-W1, GA-N1, and GA-AA1 of lower cretaceous Hauterivian to early Aptian age between 112 to 117.5 (MA) Southern Pletmos sub-basin, Bredasdorp basin offshore South Africa. The study aimed to determine the pore pressure prediction of the reservoir formation of the wells. Eaton’s resistivity and Sonic method are adopted using depth dependent normal compaction trendline (NCT) has been carried out for this study. The variation of the overburden gradient (OBG), the Effective stress, Fracture gradient (FG), Fracture pressure (FP), Pore pressure gradient (PPG) and the predicted pore pressure (PPP) have been studied for the selected wells. The overburden changes slightly as follow: 2.09g/cm3, 2.23g/cm3 and 2.24g/cm3 across the selected intervals depth of wells. The predicted pore pressure calculated for the intervals depth of selected wells GA-W1, GA-N1 and GA-AA1 also varies slightly down the depths as follow: 3,405 psi, 4,110 psi, 5,062 psi respectively. The overpressure zone and normal pressure zone were encountered in well GA-W1, while a normal pressure zone was experienced in both well GA-N1 and GA-AA1. In addition, the direct hydrocarbon indicator (DHI) was carried out by method of post-stack amplitude analysis seismic reflectors surface which was used to determine the hydrocarbon prospect zone of the wells from the seismic section. It majorly indicate the zones of thick hydrocarbon sand from the amplitude extraction grid map horizon reflectors at 13AT1 & 8AT1 and 8AT1 & 1AT1 of the well GA-W1, GA-N1 and GA-AA1 respectively. These are suggested to be the hydrocarbon prospect locations (wet-gas to Oil prone source) on the seismic section with fault trending along the horizons. No bright spot, flat spot and dim spot was observed except for some related pitfalls anomalies
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Yoo, Seung Chul. "Frequency dependent seismic reflection analysis: a path to new direct hydrocarbon indicators for deep water reservoirs." Thesis, 2007. http://hdl.handle.net/1969.1/ETD-TAMU-1933.

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To better study frequency related effects such as attenuation and tuning, we developed a frequency dependent seismic reflection analysis. Comprehensive tests on full waveform synthetics and observations from the Teal South ocean bottom seismic (OBS) data set confirmed that normal moveout (NMO) stretch could distort both frequency and amplitude information severely in shallow events and far offset traces. In synthetic tests, our algorithm recovered amplitude and frequency information ac-curately. This simple but robust target oriented NMO stretch correction scheme can be used on top of an existing seismic processing flow for further analyses. By combining the NMO stretch correction, spectral decomposition, and crossplots of am-plitude versus offset (AVO) attributes, we tested the frequency dependent workflow over Teal south and Ursa field data sets for improved reservoir characterization. As expected from NMO stretch characteristics, low frequencies have been less affected while mid and high frequency ranges were affected considerably. In seismic attribute analysis, the AVO crossplots from spectrally decomposed prestack data confirmed the improved accuracy and effectiveness of our workflow in mid and high frequency regions. To overcome poor spectral decomposition results due to low signal to noise ratio (S/N) in the Teal South application, we also implemented a substack scheme that stacks adjacent traces to increase S/N ratio while reducing the amount of data to process and increasing the accuracy of the spectral decomposition step. Synthetic tests verified the effectiveness of this additional step. An application to the Ursa, Gulf of Mexico, deep water data set showed significant improvement in high frequency data while correcting biased low frequency information.
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Books on the topic "Direct Hydrocarbon Indicators (DHIs)"

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Chelton, C. F. Manual of Recommended Practice for Combustible Gas Indicators and Portable Direct-reading Hydrocarbon Detectors. 2nd ed. American Industrial Hygiene Association,U.S., 1993.

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Book chapters on the topic "Direct Hydrocarbon Indicators (DHIs)"

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Nanda, Niranjan C. "Direct Hydrocarbon Indicators (DHI)." In Seismic Data Interpretation and Evaluation for Hydrocarbon Exploration and Production, 103–13. Cham: Springer International Publishing, 2016. http://dx.doi.org/10.1007/978-3-319-26491-2_6.

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Nanda, Niranjan C. "Direct Hydrocarbon Indicators (DHI)." In Seismic Data Interpretation and Evaluation for Hydrocarbon Exploration and Production, 117–29. Cham: Springer International Publishing, 2021. http://dx.doi.org/10.1007/978-3-030-75301-6_6.

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Conference papers on the topic "Direct Hydrocarbon Indicators (DHIs)"

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Tanasa, M. "Direct Hydrocarbon Indicators." In 4th Congress of the Balkan Geophysical Society. European Association of Geoscientists & Engineers, 2005. http://dx.doi.org/10.3997/2214-4609-pdb.26.p5-06.

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Gallagher, J. W., J. Bingham, and R. W. Simm. "Direct Hydrocarbon Indicators on the UK Atlantic Margin." In 59th EAGE Conference & Exhibition. European Association of Geoscientists & Engineers, 1997. http://dx.doi.org/10.3997/2214-4609-pdb.131.gen1997_p161.

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Bhatti, Bilal Ahmed, and R. James Brown. "Low-frequency seismic analysis and direct hydrocarbon indicators." In SEG Technical Program Expanded Abstracts 2016. Society of Exploration Geophysicists, 2016. http://dx.doi.org/10.1190/segam2016-13858356.1.

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Jiang, Ren, Yonglin Ouyang, Qingcai Zeng, Jiaqiang Huang, Pei He, Xiujiao Wang, and Lianqun Zhang. "Gas detection in tight sand with direct hydrocarbon indicators." In International Conference on Engineering Geophysics, Al Ain, United Arab Emirates, 9-12 October 2017. Society of Exploration Geophysicists, 2017. http://dx.doi.org/10.1190/iceg2017-018.

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Curia, David, Eduardo Trinchero, and Luis Vernengo. "Fluid properties and their seismic responses_ Implications for Direct Hydrocarbon Indicators." In International Congress of the Brazilian Geophysical Society&Expogef. Brazilian Geophysical Society, 2019. http://dx.doi.org/10.22564/16cisbgf2019.102.

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Santos, Luiz Fernando, Reinaldo Mozart Gama E. Silva, Marcelo Gattass, and Aristofanes Correa Silva. "Direct hydrocarbon indicators based on long short-term memory neural network." In SEG Technical Program Expanded Abstracts 2019. Society of Exploration Geophysicists, 2019. http://dx.doi.org/10.1190/segam2019-3215628.1.

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Hamborg, M., Ø. Sylta, M. Gading, and H. Løseth. "Reducing exploration risks by constraining migration models to direct hydrocarbon indicators." In 58th EAEG Meeting. Netherlands: EAGE Publications BV, 1996. http://dx.doi.org/10.3997/2214-4609.201409089.

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Fahmy, W. A., and J. M. Reilly. "Applying DHI/AVO Best Practices to Successfully Identify Key Risks Associated with a Fizz-Water Direct Hydrocarbon Indicator in the Norwegian Sea." In 9th Simposio Bolivariano - Exploracion Petrolera en las Cuencas Subandinas. European Association of Geoscientists & Engineers, 2006. http://dx.doi.org/10.3997/2214-4609-pdb.111.216.

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Fahmy, William A., and Joseph M. Reilly. "Applying DHI/AVO best practices to successfully identify key risks associated with a fizz‐water Direct Hydrocarbon Indicator in the Norwegian Sea." In SEG Technical Program Expanded Abstracts 2006. Society of Exploration Geophysicists, 2006. http://dx.doi.org/10.1190/1.2370320.

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Johnson, Andrew C., Jeffrey Miles, Laurent Mosse, Robert Laronga, Violeta Lujan, Niranjan Aryal, and Dozie Nwosu. "INTEGRATING A NOVEL CHLORINE MEASUREMENT WITH RESISTIVITY, DIELECTRIC DISPERSION, AND 2D NMR TO RESOLVE SALINITY AMBIGUITY: CASE STUDIES IN ORGANIC SHALE FORMATIONS." In 2021 SPWLA 62nd Annual Logging Symposium Online. Society of Petrophysicists and Well Log Analysts, 2021. http://dx.doi.org/10.30632/spwla-2021-0077.

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Formation water saturation is a critical target property for any comprehensive well log analysis program. Most techniques for computing saturation depend heavily on an analyst’s ability to accurately model resistivity measurements for the effects of formation water resistivity and rock texture. However, the pre-requisite knowledge of formation water properties, particularly salinity, is often either unknown, varying with depth or lateral extent, or is difficult to derive from traditional methods. A high degree of variability may be present due to fluid migration from production, water injection, or various geological mechanisms. In unconventional reservoirs, the complexity of the rocks and pore structure further complicates traditional interpretation of the available well logs. These factors introduce significant uncertainties in the computed fluid saturations and therefore can substantially affect final reserves estimates. A novel technique in geochemical spectroscopy has recently been introduced to distinguish the chlorine signals of the formation and borehole. The new, quantitative measurement of formation chlorine enables a direct calculation of bulk water volume for a given formation water salinity. When integrated into a multi-physics log analysis workflow, the chlorine-derived water volume can provide critical information on fluid saturations, hydrocarbon-in-place, and producibility indicators. This additional information is especially useful for characterizing challenging and complex unconventional reservoirs. We present the new technique through several full petrophysical evaluation case studies in organic shale formations across the U.S., including the Midland, Delaware, Marcellus, and DJ basins. We solve for formation-specific water salinity and bulk water volume through an optimization that combines chlorine concentration with resistivity and dielectric measurements. These outputs are integrated into comprehensive petrophysical evaluations, leveraging a suite of advanced well log measurements to compute final fluid and rock properties and volumetrics. The evaluations include geochemical mineralogy logs, 2D NMR analyses, dielectric dispersion analyses, basic log measurements, and multi-mineral models. The results underscore the utility of the new spectroscopy chlorine log to reduce petrophysical model uncertainties in an integrated workflow. While this workflow has been demonstrated here in several U.S. organic shale case studies, the fundamental challenges it addresses will make it a valuable solution for a range of unconventional reservoirs globally.
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