To see the other types of publications on this topic, follow the link: Direct Hydrocarbon Indicators (DHIs).
Journal articles on the topic 'Direct Hydrocarbon Indicators (DHIs)'
Create a spot-on reference in APA, MLA, Chicago, Harvard, and other styles
Consult the top 50 journal articles for your research on the topic 'Direct Hydrocarbon Indicators (DHIs).'
Next to every source in the list of references, there is an 'Add to bibliography' button. Press on it, and we will generate automatically the bibliographic reference to the chosen work in the citation style you need: APA, MLA, Harvard, Chicago, Vancouver, etc.
You can also download the full text of the academic publication as pdf and read online its abstract whenever available in the metadata.
Browse journal articles on a wide variety of disciplines and organise your bibliography correctly.
1
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.
Full textAbstract:
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.
2
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.
Full textAbstract:
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.
3
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.
Full textAbstract:
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.
4
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.
Full textAbstract:
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.
5
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.
Full textAbstract:
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.
6
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.
Full textAbstract:
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.
7
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.
Full textAbstract:
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.
8
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.
Full textAbstract:
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.
9
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.
Full text
10
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.
Full text
11
Lerche, Ian. "Direct Detection of Hydrocarbons: Some Preliminary Thoughts and Questions." Energy Exploration & Exploitation 5, no. 4 (August 1987): 265–85. http://dx.doi.org/10.1177/014459878700500402.
Full textAbstract:
After briefly reviewing seismic signatures associated with the direct detection of hydrocarbons, some possible non-hydrocarbon sources of seismic signatures which may masquerade as hydrocarbon patterns are considered. Four broad avenues of research are suggested which may allow greater assurance in identifying and interpreting seismic signatures associated with hydrocarbon accumulations than is currently enjoyed. It is also suggested that any available information extending upon any part of this paper will increase the base of knowledge of seismic direct detection indicators.
12
Francis, A., M. Millwood Hargrave, P. Mulholland, and D. Williams. "Real and relict direct hydrocarbon indicators in the East Irish Sea Basin." Geological Society, London, Special Publications 124, no. 1 (1997): 185–94. http://dx.doi.org/10.1144/gsl.sp.1997.124.01.11.
Full text
13
VYZHVA, Sergiy, Ihor SOLOVYOV, Ihor МYKHALEVYCH, Viktoriia KRUHLYK, and Georgiy LISNY. "APPLICATION OF DIRECT HYDROCARBON INDICATORS FOR OIL AND GAS PROSPECTING IN THE DNIPRO-DONETS DEPRESSION." Ukrainian Geologist, no. 1-2(44-45) (June 30, 2021): 99–108. http://dx.doi.org/10.53087/ug.2021.1-2(44-45).238953.
Full textAbstract:
Based on the results of numerous seismic studies carried out in the areas and fields of the Dnipro-Donets depression, the strategy to identify hydrocarbon traps in this region has been developed taking into account modern requirements for prospecting and exploration of gas and oil fields. The studies are designed to determine the favorable zones of hydrocarbon accumulations based on the analysis of the structural-tectonic model. A necessary element for solving such a problem is to aaply direct indicators of hydrocarbons to predict traps of the structural, lithological or combined type. It was determined that an effective approach to identify hydrocarbon traps in the region is attribute analysis employing seismic attributes such as seismic envelope, acoustic impedance or relative acoustic impedance. In most cases of practical importance, the analysis of the distribution of the values of these attributes turned out to be sufficient for performing the geological tasks. It is given an example of extracting additional useful information on the spatial distribution of hydrocarbon traps from volumetric images obtained from seismograms of common sources with a limited range of ray angles inclinations. To analyze the distributions of seismic attribute values, it is recommended to use the Geobody technology for detecting geological bodies as the most effective when using volumetric seismic data. The distributions of various properties of rocks, including zones of increased porosity or zones of presence of hydrocarbons are determined depending on the types of seismic attributes used in the analysis,. The use of several seismic attributes makes it possible to identify geological bodies saturated with hydrocarbons with increased porosity and the like. The paper provides examples of hydrocarbon traps recognition in the areas and fields of the Dnipro-Donets depression practically proved by wells. A generalization on the distribution of promising hydrocarbon areas on the Northern flank of the Dnipro-Donets depression and the relationship of this distribution with the identified structural elements of the geological subsoil is made.
14
Ensley, Ross Alan. "Evaluation of direct hydrocarbon indicators through comparison of compressional‐ and shear‐wave seismic data: a case study of the Myrnam gas field, Alberta." GEOPHYSICS 50, no. 1 (January 1985): 37–48. http://dx.doi.org/10.1190/1.1441834.
Full textAbstract:
Shear waves differ from compressional waves in that their velocity is not significantly affected by changes in the fluid content of a rock. Because of this relationship, a gas‐related compressional‐wave “bright spot” or direct hydrocarbon indicator will have no comparable shear‐wave anomaly. In contrast, a lithology‐related compressional‐wave anomaly will have a corresponding shear‐wave anomaly. Thus, it is possible to use shear‐wave seismic data to evaluate compressional‐wave direct hydrocarbon indicators. This case study presents data from Myrnam, Alberta which exhibit the relationship between compressional‐ and shear‐wave seismic data over a gas reservoir and a low‐velocity coal.
15
Brown, Alistair R., and William L. Abriel. "Detection of hydrocarbons using non-bright-spot seismic techniques." Interpretation 2, no. 4 (November 1, 2014): SP1—SP4. http://dx.doi.org/10.1190/int-2014-0138.1.
Full textAbstract:
Interpretation technology for the direct detection of hydrocarbons with stacked seismic reflections is focused mainly on bright spot systems in which the acoustic impedance of the reservoir is lower than the overburden and underburden. Interpretation of polarity reversal and dim spot systems, in which the acoustic impedance of the reservoir is higher than the overburden or underburden, requires the interpreter to use a different and more complicated set of rules to validate these as direct hydrocarbon indicators.
16
Ma, Jiqiang, Jianhua Geng, and Tonglou Guo. "Prediction of deep-buried gas carbonate reservoir by combining prestack seismic-driven elastic properties with rock physics in Sichuan Basin, southwestern China." Interpretation 2, no. 4 (November 1, 2014): T193—T204. http://dx.doi.org/10.1190/int-2013-0117.1.
Full textAbstract:
The prediction of seismic reservoirs in marine carbonate areas in the Sichuan Basin, southwestern China, is very challenging because the target zone is deeply buried (more than 6 km), with multiphase tectonic movements, complex diagenesis, and low porosity, and the incident angle of the seismic data is finite. We developed reliable hydrocarbon indicators of a marine carbonate deposit based on prestack elastic impedance (EI) and well observations. Although the hydrocarbon indicators can be calculated from elastic parameters, the inversion for EI-driven elastic attributes is usually unstable. To constrain the inversion process, we discovered a new strategy to recover the elastic properties from EIs within a Bayesian framework (called Bayesian elastic parameter inversion from elastic impedance). We applied the strategy to a carbonate reef identified at the center of a study line based on the geologic context and the seismic reflection patterns. We then used rock-physics analyses to classify the lithologies and the reservoir at a well location. Rock-physics modeling quantified the hydrocarbon sensitivity of the elastic attributes. Fluid substitution was used to investigate the effects of pore fluids on the elastic properties. A comparison of two synthetic amplitude-versus-angle responses (for gas and brine saturation) with real seismic data showed that the reservoir was gas charged. Using well-based crossplot analyses, reliable direct hydrocarbon indicators can be constructed for a deeply buried gas reservoir and were effective for interpretation in an area of marine carbonates in the Sichuan Basin.
17
Raeuchle, Sandra K., William A. Ambrose, M. Saleem Akhter, Jhonny Casas, Lourdes Salamanca, Pedro Muñoz, and Alfredo Leon. "Integrated reservoir study, Lower Eocene Misoa reservoirs, VLA-6/9/21 Area, Block I, Phase 2, Stage 2, Lagunillas Field, north‐central Lake Maracaibo, Venezuela." GEOPHYSICS 62, no. 5 (September 1997): 1496–509. http://dx.doi.org/10.1190/1.1444253.
Full textAbstract:
Twenty‐eight geologically targeted, field development opportunities, including a variety of deeper pool opportunities that could significantly add to Maraven's (affiliate of PDVSA) reserve base, are identified in Lower Eocene Misoa reservoirs in the Stage 2 Area in Block I in north‐central Lake Maracaibo, Venezuela with the help of integrated geophysical, geological, petrophysical, and engineering analyses. Seismic rms amplitudes are instrumental in detecting and mapping trends of lithofacies and were integrated into stratigraphic models. Amplitude response to net sand thickness is a linear relationship. The amplitude signature also captures hydrocarbon charge as evidenced by bright amplitudes coincident with structural, fault‐bounded culminations. These direct hydrocarbon indicators (DHI) can result from as low as 2% miscible gas fraction within the hydrocarbon column.
18
Snyder, Allan G., and Keith H. Wrolstad. "Direct detection using AVO, Central Graben, North Sea." GEOPHYSICS 57, no. 2 (February 1992): 313–25. http://dx.doi.org/10.1190/1.1443245.
Full textAbstract:
An amplitude versus offset (AVO) study was undertaken for Lines ECL-1 and -2 and Well A of the United Kingdom North Sea to determine if variations in fluid saturation can be detected in Eocene sand mounds. These features are a major play in this area. The Eocene sands contain gas and oil in Well A. Elastic modeling using the well data was done to match the seismic common midpoint (CMP) gather. Target zone fluid saturations in the model were then altered to investigate changes in AVO and stacked trace response. The model and field data were processed using the same processing steps and parameters. Seismic offset dependent amplitude stack (SODAS), a color display system, was used to display the AVO results for the field and model data. It was found that gas, oil, and water sands could be distinguished from each other, though full and partial gas saturation were indistinguishable. Clay content, porosity, and multiple reflections also had important effects on the AVO response. On the basis of the hydrocarbon indicators that were investigated we then interpreted the hydrocarbon limits on Line ECL-1 with well control and evaluated Line ECL-2, which has an undrilled prospect. From our analysis, we concluded that waterbearing sands were most likely present in the prospect area on Line ECL-2, though the data is rather inconclusive.
19
Smolin, S. N., and G. M. Mitrofanov. "SEARCH FOR HYDROCARBON ACCUMULATIONS IN POROUS FRACTURED RESERVOIRS USING THE PRONY TECHNOLOGY." Geology and mineral resources of Siberia, no. 1 (2021): 74–87. http://dx.doi.org/10.20403/2078-0575-2021-1-74-87.
Full textAbstract:
The search for nonstructural hydrocarbon accumulations is a Herculean task that requires the use of delicate tools. Such tools include the Prony filtration technology. It allows for direct qualitative forecasting of hydrocarbon bearing features based on frequency-dependent analysis of the observed wave field of CDP reflection-time sections and includes four steps. The article shows capabilities of technology and specific examples of its application by correlation of frequency-dependent Prony images of wave fields with deep drilling data. The performed studies were carried out using CDP 2D seismic data and deep drilling data of 32 wells obtained in the territory of the West Siberian Plate, mainly for the Middle Jurassic (Late Bajocian-Bathonian, Malyshev horizon) interval of terrigenous-sedimentary deposits. At times, the underlaying and overlying Middle and Upper Jurassic deposits were captured. The manifestation forms of various oil and stratum water accumulations and their possible prospecting indicators, as well as signs of the absence of reservoirs are given. As an example, the manifestation and possible prospecting indicators of gas accumulation from a neighboring region within the West Siberian Plate are shown.
20
Lur’E, M. A., and F. K. Shmidt. "CLASSIFICATION OF OILS. SULFUR CONTENT AS GENETIC CLASSIFICATION SIGN." Oil and Gas Studies, no. 4 (August 30, 2018): 115–21. http://dx.doi.org/10.31660/0445-0108-2018-4-115-121.
Full textAbstract:
In the article we considered the following variants of oil classification: technological, chemical, and geochemical (genetic). Applicability of the classification indicators (hydrocarbon composition, fractional composition of oils, asphaltic-resinous components, sulfur content, metal content) is discussed to separate oils to different chemical types Stable direct correlations between sulfur concentration in oils and diverse characteristics of oils allow to consider the sulfur content as an indicator of genetic nature.
21
Bryndzia, L. Taras, Nishank Saxena, Sean S. Dolan, Mark G. Kittridge, Mark L. Rosenquist, and Neil R. Braunsdorf. "Interpreting direct hydrocarbon indicators of low-API biodegraded oils — A case study from a deepwater South Atlantic Basin." Leading Edge 35, no. 6 (June 2016): 511–15. http://dx.doi.org/10.1190/tle35060511.1.
Full text
22
Jiang, Lian, and John P. Castagna. "On the rock-physics basis for seismic hydrocarbon detection." GEOPHYSICS 85, no. 1 (November 18, 2019): MR25—MR35. http://dx.doi.org/10.1190/geo2018-0801.1.
Full textAbstract:
One of the primary fluid indicators for direct hydrocarbon detection in sandstones using seismic reflectivity is the difference between the saturated-rock P-wave impedance and the rock-frame impedance. This can be expressed in terms of the difference between the observed P-wave impedance squared and a multiplier times the square of the observed S-wave impedance. This multiplier is a fluid discrimination parameter that laboratory and log measurements suggest varies over a wide range. Theoretically, this parameter is related to the ratio of the frame bulk and shear moduli and the ratio of the frame and fluid-saturated rock densities. In practice, empirical determination of the fluid discrimination parameter may be required for a given locality. Given sufficient data for calibration, the parameter can be adjusted so as to best distinguish hydrocarbon-saturated targets from brine-saturated rocks. Using an empirically optimized fluid discrimination parameter has a greater impact on hydrocarbon detection success rate in the oil cases studied than for gas reservoirs, for which there is more latitude. Application to a wide variety of well-log and laboratory measurements suggests that the empirically optimized parameter may differ from direct theoretical calculations made using Gassmann’s equations. Combining laboratory and log measurements for sandstones having a broad range of frame moduli, varying from poorly consolidated to highly lithified, reveals a simple linear empirical relationship between the optimized fluid discrimination parameter and the squared velocity ratio of brine-saturated sandstones.
23
Rahman, Morshedur, SM Mainul Kabir, and Janifar Hakim Lupin. "Shallow Gas Prospect Evaluation in Shahbazpur Structure Using Seismic Attributes Analysis - a Case Study for Bhola Island, Southern Bangladesh." Dhaka University Journal of Science 64, no. 2 (July 31, 2016): 135–40. http://dx.doi.org/10.3329/dujs.v64i2.54486.
Full textAbstract:
Shahbazpur structure is located in the southern Part of the central deep basin in the Hatia trough, where lie all the largest Gas fields of Bangladesh. A method is established to delineate the structural mapping precisely by interpreting four 2D seismic lines that are acquired over Shahbazpur structure. Moreover direct hydrocarbon indicators (DHI) related attributes are analyzed for further confirmation for presence of hydrocarbon. To do this synthetic seismogram generation, seismic to well tie, velocity modelling and depth conversion are performed. A limited number of seismic attributes functions that are available in an academic version of Petrel software are applied to analyze attributes. Seismic attribute analyses that are used in this interpretation mainly are associated to bright spot detection. Presence of bright spots or high amplitude anomaly over the present Shahbazpur structure, reservoir zone are observed. This signature will play a very important role in next well planning on the same structure to test the shallow accumulation of hydrocarbon. For better understanding of this shallow reserve, it is suggested to acquire 3D seismic data over Shahbazpur structure which will help to evaluate the hydrocarbon accumulation and to identify gas migration pathways.
Dhaka Univ. J. Sci. 64(2): 135-140, 2016 (July)
24
Connolly, David L. "Visualization of vertical hydrocarbon migration in seismic data: Case studies from the Dutch North Sea." Interpretation 3, no. 3 (August 1, 2015): SX21—SX27. http://dx.doi.org/10.1190/int-2015-0007.1.
Full textAbstract:
Previous 3D visualization studies in seismic data have largely been focused on visualizing reservoir geometry. However, there has been less effort to visualize the vertical hydrocarbon migration pathways, which may provide charge to these reservoirs. Vertical hydrocarbon migration was recognized in normally processed seismic data as vertically aligned zones of chaotic low-amplitude seismic response called gas chimneys, blowout pipes, gas clouds, mud volcanoes, or hydrocarbon-related diagenetic zones based on their morphology, rock properties, and flow mechanism. Because of their diffuse character, they were often difficult to visualize in three dimensions. Thus, a method has been developed to detect these features using a supervised neural network. The result is a “chimney” probability volume. However, not all chimneys detected by this method will represent true hydrocarbon migration. Therefore, the neural network results must be validated by a set of criteria that include (1) pockmarked morphology, (2) tie to shallow direct hydrocarbon indicators, (3) origination from known or suspected source rock interval, (4) correlation with surface geochemical data, and (5) support by basin modeling or well data. Based on these criteria, reliable chimneys can be extracted from the seismic data as 3D geobodies. These chimney geobodies, which represent vertical hydrocarbon migration pathways, can then be superimposed on detected reservoir geobodies, which indicate possible lateral migration pathways and traps. The results can be used to assess hydrocarbon charge efficiency or risk, and top seal risk for identified traps. We investigated a case study from the Dutch North Sea in which chimney processing results exhibited vertical hydrocarbon pathways, originating in the Carboniferous age, which provided the charge to shallow Miocene gas sands and deep Triassic prospects.
25
Wojcik, Krzysztof M., Irene S. Espejo, Adebukonla M. Kalejaiye, and Otuka K. Umahi. "Bright spots, dim spots: Geologic controls of direct hydrocarbon indicator type, magnitude, and detectability, Niger Delta Basin." Interpretation 4, no. 3 (August 1, 2016): SN45—SN69. http://dx.doi.org/10.1190/int-2016-0062.1.
Full textAbstract:
Bright-spot amplitude anomalies have been an attractive exploration target in the Niger Delta since the early 1970s, and the bright-spot play can now be considered mature. There is a need to extend the bright-spot exploration success to include other types of direct hydrocarbon indicators such as dim spots or polarity reversals. Several true dim spots have been identified in the basin, calibrated with well data and characterized in detail to enable a systematic analysis of the geologic factors that produce the dim-spot response. Dim spots in deeper stratigraphic intervals reflect a high degree of compaction and quartz cementation and are characterized by minimal fluid signal and commonly very low detectability. Robust and detectable dim spots have been identified in shallow marine/deltaic systems in the Niger Delta in shallower stratigraphic intervals with a relatively strong fluid signal. The key factor promoting a robust dim-spot response is the presence of acoustically soft, clay-rich shales as the bounding lithology. The variability of the bounding shales in the Niger Delta is stratigraphically constrained and, to some degree, predictable. The change from hard mudstones to soft claystones, which can be recognized in seismic data, may result in a transition from bright to dim spots, possibly taking place within the same stratigraphic interval and over short distances. Many clastic basins globally follow a similar stratigraphic and diagenetic evolution; thus, the Niger Delta example may be a good analog for dim-spot plays elsewhere.
26
Eadington, P. J., P. J. Hamilton, and G. P. Bai. "FLUID HISTORY ANALYSIS — A PROSPECT EVALUATION." APPEA Journal 31, no. 1 (1991): 282. http://dx.doi.org/10.1071/aj90022.
Full textAbstract:
Fluid history analysis investigates oil migration and basin hydrology which are important factors affecting hydrocarbon charge to reservoirs. A combination of direct observation and measurement at the mineralogical scale and numerical simulations is used.Fluid inclusions in diagenetic minerals are used to make direct observations about the timing of oil migration and to measure palaeotemperatures. Isotopic compositions of diagenetic minerals are measured for age determination and to identify the sources of ancient pore waters in order to interpret basin hydrology.Integrated interpretation of time specific and time dependent thermal indicators provides a detailed thermal history of the rocks as input to numerical simulations of oil generation. Hydrocarbon fluid inclusions provide an observational check on the theoretical predictions.In the Eromanga Basin in south-west Queensland two areas with different oil migration history are identified. On the Jackson-Challum trend there was a pulse of oil migration synchronous with quartz cementation in late Cretaceous time. On the Tintaburra-Bodalla South trend oil migration followed quartz cementation from the mid Cretaceous to the present day. Jackson oil migrated while the isotopic composition of pore water became increasingly oxygen-18 enriched indicating diagenetic modification during slow flow of groundwater. Tintaburra oil migration occurred during the present regime of downdip flow of relatively oxygen-18 depleted groundwater characteristic of a meteoric origin.
27
Wensaas, L., H. F. Shaw, K. Gibbons, P. Aagaard, and H. Dypvik. "Nature and causes of overpressuring in mudrocks of the Gullfaks Area, North Sea." Clay Minerals 29, no. 4 (October 1994): 439–49. http://dx.doi.org/10.1180/claymin.1994.029.4.04.
Full textAbstract:
AbstractPore-fluid pressure gradients in Lower Tertiary to Upper Jurassic mudrocks in the Gullfaks area show significant variations, both between and within individual structural compartments. Detection and quantification of abnormal pore-pressures, based on drilling parameters and wire line logs, are significantly influenced by petrological variations in the mudrocks and do not provide adequate direct pressure indicators. Empirical models show that the degree of overpressuring in mudrocks above the Gullfaks reservoirs cannot be fully explained by processes such as shale dehydration, compaction disequilibrium, aquathermal effects or in situ hydrocarbon generation, and other processes, such as caprock failure and subsequent migration of hydrocarbons (mainly gas) into the overlying mudrocks, appear to be influential in generating the observed pattern of overpressure.
28
Edwards, Rowan, Marcus Sanderson, Pedro Martinez Duran, Gregor Duval, and Mike King. "Enhancing SAR seep interpretation with broadband seismic: a case study from the Timor Trough." APPEA Journal 57, no. 2 (2017): 818. http://dx.doi.org/10.1071/aj17019.
Full textAbstract:
By combining sea surface seep data derived from synthetic aperture radar imagery and 2D seismic acquired by CGG’s Multi-client New Ventures, a seeps to seismic workflow has been developed which allows the linking of interpreted surface seeps with features on the seabed and within the subsurface related to seepage. The project combines these data sources in order to create hotspot maps which describe the quality and frequency of these seep related features, be it direct hydrocarbon indicators, possible migration pathways, fluid escape features or seabed features. By combing these maps with the surface seeps, localised points of hydrocarbon generation, migration and escape are able to be identified. 3D modelling software is utilised to link these hot spots within the seismic along strike and identify the most important and continuous structures. By identifying and understanding the geology where hydrocarbons are reaching the surface it is possible to better identify potential locations where the same hydrocarbons may instead be properly trapped. This allows the efficient identification of prospects within a basin.
29
Wolter, P. J., and P. L. Harrison. "Amplitude with Offset and Direct Hydrocarbon Indicators Enable Mapping of Gas Reservoirs in the Golden Beach, Baleen and Patricia Fields, Gippsland Basin, Victoria." Exploration Geophysics 19, no. 1-2 (March 1988): 205–13. http://dx.doi.org/10.1071/eg988205.
Full text
30
Vyzhva, S., I. Solovyov, I. Mihalevich, V. Kruhlyk, and G. Lisny. "USE OF QUANTITATIVE DATA OF 3D SEISMIC EXPLORATION FOR DETECTION OF TRAPS OF HYDROCARBONS WITH IN THE NORTH SIDE OF THE DNIEPER-DONETSK DEPRESSION." Visnyk of Taras Shevchenko National University of Kyiv. Geology, no. 4 (91) (2020): 35–41. http://dx.doi.org/10.17721/1728-2713.91.05.
Full textAbstract:
Based on the results of numerous seismic surveys conducted on the areas and deposits of the northern side of the Dnieper-Donetsk depression, an appropriate strategy for detecting hydrocarbon traps in this region has been determined. This takes into account modern requirements for exploration and prospecting of gas and oil deposits. They consist in determining the probable zones of accumulation of hydrocarbons based on the analysis of the structural-tectonic model. At the same time, the use of direct hydrocarbon indicators to predict structural, lithological or combined traps is also a necessary element in solving this problem. It has been shown that an effective approach to detecting hydrocarbon traps in this region is attribute analysis using seismic attributes such as seismic signal envelope, acoustic impedance or relative acoustic impedance. In most practically important cases, the analysis of the distribution of values of these attributes was sufficient to solve geological problems. At the same time, an example of extracting additional useful information on the spatial distribution of hydrocarbon traps from volumetric seismic images obtained from seismograms of common sources with a limited range of seismic angle inclinations is given. To analyze the distributions of seismic attribute values it is recommended to use geobody technology as the most effective one when using volumetric seismic data. Depending on the combination of seismic attributes involved in the analysis, the distributions of different properties of rocks are determined, in particular the zone of increased porosity or the presence of hydrocarbons. Analysis with the simultaneous use of several seismic attributes allows to directly identify hydrocarbon-rich geological bodies with high porosity and the like. The paper presents examples of detection of hydrocarbon traps in the areas and deposits of the northern side of the Dnieper-Donetsk depression, which are confirmed by drilled wells. An example of providing recommendations for wells drilling using the distributions of values of different seismic attributes is given. Generalizations are made on the distribution of promising areas for the presence of hydrocarbons on the northern side of the Dnieper-Donetsk depression and the ratio of this distribution with the identified structural elements of the geological environment.
31
Amiribesheli, Said, and Andrew Weller. "The prospectivity of the Cape Vogel Basin, Papua New Guinea." APPEA Journal 59, no. 2 (2019): 840. http://dx.doi.org/10.1071/aj18094.
Full textAbstract:
The frontier and underexplored Cape Vogel Basin (CVB), north of the Papuan Peninsula, is thought to be underlain by Late Palaeocene–Eocene oceanic crust and overlain by Cenozoic sediments. Several impartial data provide evidence of working petroleum system(s) including a flow of oil from a 1920s well, and two 1970s wells that encountered minor hydrocarbon traces and good source material. The 1970s wells chased Miocene reef plays (like the discoveries in the Gulf of Papua). No Miocene reefs were encountered, with both wells terminating in volcanics. Integration of open-file 2D seismic, modern 2D PSDM seismic and shipborne gravity and magnetic data improves the subsurface imaging and thus understanding of prospectivity. The data reveal a significant sedimentary section (including Mesozoic sediments) and that the volcanics are not laterally continuous (i.e. products of short periods of volcanism). The data also suggests several Mesozoic–Cenozoic plays (e.g. carbonate reefs, incised canyons). Repeatable sea surface slicks, and observable bottom-simulating reflectors and direct hydrocarbon indicators, also provide evidence of working petroleum system(s). It is hypothesised that the CVB has affinities with the Gulf of Papua with the extension of the Australian craton north of the Papuan Peninsula, with widespread deposition in the Mesozoic–Cenozoic, and with source rocks estimated to be within the hydrocarbon generative window. With incorporation of onshore data and presence of significant gravity low, it is postulated that the central and north-west were less susceptible to Late Cretaceous and Palaeocene differential uplift and erosion (related to Coral Sea breakup and extension), and thus have a higher chance of Late Mesozoic preservation.
32
Tingate, P. R., A. Khaksar, P. van Ruth, D. Dewhurst, M. Raven, H. Young, R. Hillis, and K. Dodds. "GEOLOGICAL CONTROLS ON OVERPRESSURE IN THE NORTHERN CARNARVON BASIN." APPEA Journal 41, no. 1 (2001): 573. http://dx.doi.org/10.1071/aj00029.
Full textAbstract:
A small, but significant fraction of wells drilled in the Northern Carnarvon Basin have encountered problems with overpressure: better pore pressure prediction would improve safety and economy for drilling operations. In the Northern Carnarvon Basin the occurrence of overpressure and likely mechanisms are under investigation as part of the Australian Petroleum Cooperative Research Centre (APCRC) Research Program on Pore Pressure Prediction. Previous workers have proposed a number of mechanisms as the main cause of overpressure including undercompaction, hydrocarbon generation, horizontal stress and clay reactions.A preliminary regional study was undertaken incorporating over 400 well completion reports which identified approximately 60 wells with mud weights greater than 1.25 S.G. A subset of these wells was investigated and more reliable but much scarcer pressure indicators such as kicks or direct pressure measurements were examined. Depth-pressure profiles of wells across the region are variable and commonly show pressure compartmentalisation. Using a range of indicators, it was observed that overpressured strata in the Barrow Subbasin:occur over a wide depth range (2,500 to 4,000+ mbsl);occur over a wide stratigraphic range (Late Triassic to Late Cretaceous);are not regionally limited by major structural boundaries;are associated with sequences dominated by finegrained sediments with variable clay mineralogy; and in depositionally, or structurally, isolated sandstones; andmainly to the west of the Barrow and Dampier Subbasins around the Alpha Arch and Rankin Trend, coinciding with thickest Tertiary deposition.Previous published work in the study area has tended to support hydrocarbon generation as the primary cause of overpressure, though more recent publications have emphasised compaction disequilibrium. The log response (DT, RHOB and NPHI) of overpressured clay-rich strata has been investigated to constrain the type of overpressure mechanism. A normal compaction trend has been derived for four stratigraphic groupings; Muderong Shale, Barrow Group, Jurassic and Triassic. All overpressure occurrences were accompanied by an increase in sonic transit time. Not all wells have suitable log data for evaluation, but all stratigraphic groups show some evidence of elevated porosity associated with overpressure consistent with disequillibrium compaction as a dominant mechanism. Overpressures in the Barrow Group in Minden-1 and the Jurassic section within Zeepaard–1 do not have accompanying porosity anomalies suggesting a different overpressure mechanism model is needed.
33
MAKSEEV, Daniil Sergeevich, Kirill Igorevich AKSENTOV, Renat Belalovich CHAKIROV, Sergey Andreevich FEDOROV, and Katerina Sergeevna FEDOROVA. "Anomalous geochemical fields of ore elements of the South Tatarian sedimentary basin (Tatar Strait, Sea of Japan)." NEWS of the Ural State Mining University 1, no. 2 (June 15, 2020): 39–47. http://dx.doi.org/10.21440/2307-2091-2020-2-39-47.
Full textAbstract:
Introduction. Currently, sea territories for production and exploration of hydrocarbon raw materials and ore deposits have been increased. Geochemical survey of seafloor sediments is of great interest among direct methods for finding deposits. One of the most important objects for such work is the Tatar Strait, in the territory of which high concentrations of useful elements can be found. Purpose of the work: to study the geochemical characteristics of seafloor sediments of the South Tatarian sedimentary basin in order to identify possible ore fields within its territory. Methods and materials. The chemical composition of seafloor sediments was analyzed, according to which maps of geochemical fields were constructed using the ArcGis program. The results of the chemical assays are obtained from the Delta Olympus X-ray fluorescent spectrometer. The number of samples obtained is 62. Results. The contents and redistribution of 21 chemical elements on the studied area were studied. Only five elements have geochemical anomalies or elevated contents that may indicate possible ore deposits: Ti, Zr, Mn, V, S. The main zones of concentration of these elements are in the shelf and bathyal areas. The characteristics of distribution of these elements over the area of the South Tatarian sedimentary basin are given and anomalous geochemical fields are identified. Conclusions. The presence of geochemical indicators of placers of titanium raw materials confined to the river fans of the Tokhtinka, Zhulman, Nemi, Ptichya and to the mechanical barrier in the region of Sovgavan uplift has been established. Promising zones of hydrocarbon concentration due to the high sulfur contents in the zone of the dynamic influence of faults (mainly fissure displacement) along the boundaries of the Terneysky trough in its western and eastern regions have been identified.
34
Reymond, S. B. "NEW SEISMIC METHODS AND POTENTIAL FORTHE REGION." APPEA Journal 40, no. 1 (2000): 326. http://dx.doi.org/10.1071/aj99018.
Full textAbstract:
New seismic data types and new interpretation tools are rapidly changing and expanding the applicability of seismic methods. In Australia, the hydrocarbon and mining industries are both using an increased proportion of 3D seismic data to improve lateral predictability and to reduce exploration and production risks and costs. New techniques and workflows described below are expected to come into more common usage over the next five years.3D reservoir characterisation workflows integrate all reservoir data types including well log measurements, seismic data, reservoir models and simulations. Within the domain of seismic data, complementary data types, such as 3D, 4D, 4C, AVO and down-hole seismic, need to be synthesised into a single optimum reservoir representation. One way of producing such results is by using seismic classification which is based on a set of geostatistical and neural network algorithms to produce a single class map or cube mapping reservoir parameters with an uncertainty estimate associated with each trace and sample location.Seismic classification is applied to two types of seismic data: attribute grids and 3D seismic attribute cubes. Seismic classification provides a tool for generalised inversion of seismic data for lithofacies, faults and fluids (DHI, Direct Hydrocarbon Indicators). At the acquisition and processing stages of seismic data, the same classification algorithms are used to assess data quality to quantify and improve seismic data quality.Recent developments in seismic attributes have shown that additional reservoir characterisation information is obtained by decomposing the seismic trace into a set of polynomial coefficients. Such seismic attributes are computed both on the seismic trace and on a synthetic trace computed along the borehole trajectory in order to calibrate the seismic attribute by measured reservoir parameters.An increasing number of 3D attribute cubes or transforms of the raw seismic volume are used by geophysicists to better capture lateral changes in seismic response. The potential and pitfalls of 3D attribute cubes are illustrated with reference to Australasian examples.Increasing interest is also being shown in fault and fracture mapping bom seismic data with applications in both the mining and hydrocarbon industries. Fault mapping and automated extraction can both be based on structural seismic attribute grids and cubes.
35
Passmore, V. L., P. E. Williamson, T. U. Mating, and A. R. G. Gray. "THE GULF OF CARPENTARIA—A NEW BASIN AND NEW EXPLORATION TARGETS." APPEA Journal 33, no. 1 (1993): 297. http://dx.doi.org/10.1071/aj92021.
Full textAbstract:
The sparsely explored Gulf of Carpentaria is a shallow water frontier area of stacked basins. The petroleum potential was not tested by the one offshore well drilled in the Gulf in 1984.Recent re-interpretation of offshore seismic in Queensland waters delineated the Bamaga Basin, a new infrabasin below the Carpentaria Basin. This new basin is a northerly trending asymmetrical sag basin that continues north of the international boundary. The Bamaga Basin, containing up to 1.8 seconds of gently folded and faulted sediments, is untested and offers a new exploration objective. Apparent high velocities make the age of the basin uncertain, but Paleozoic reservoir and source rocks, similar to sedimentary rocks in nearby basins, are inferred, although analogue basins are not readily identifiable.Bamaga Basin source rock burial is sufficient to generate hydrocarbons and could source reservoirs in the Bamaga and Carpentaria Basins via migration along faults. Possible direct hydrocarbon indicators increase support for the presence of hydrocarbons in the Gulf.Structural and stratigraphic plays in the Carpentaria Basin that provide new exploration targets include: basal sandstones onlapping areas of higher relief or filling basin floor depressions, sandstone layers within the Wallumbilla Formation draping highs and possible carbonate zones appearing as high amplitude chaotic reflectors. Within the Bamaga Basin, horst, fault structures and anticlinal features are potential structural plays, and termination of units against the main unconformity are possible stratigraphic play targets.
36
Uruski, C. I., B. D. Field, and R. Funnell. "THE EAST COAST BASIN OF NEW ZEALAND, AN EMERGING PETROLEUM PROVINCE." APPEA Journal 45, no. 1 (2005): 563. http://dx.doi.org/10.1071/aj04043.
Full textAbstract:
More than 300 oil and gas seeps are known in the onshore East Coast Basin of North Island, New Zealand. Spectacular geological structures have been explored by more than 40 wells, only three of which have been offshore. Results are tantalising, with 70% of wells yielding oil or gas shows. Westech’s two gas discoveries onshore at Kauhauroa and Tuhara in northern Hawkes Bay remain un-developed at present.Strong gas shows were encountered in both open-file wells drilled offshore and elevated gas readings were recorded in the recent Tawatawa–1 well, but reservoir quality was poor.Nevertheless, good reservoir facies are abundant in the East Coast Basin. A wide range of Miocene and Pliocene sands and limestones, with porosities of 20% and above are known from outcrop and wells. But, modern, good quality seismic data are essential to allow sequence stratigraphic interpretation and a reasonable likelihood of predicting the distribution of reservoir facies. As part of its program to stimulate exploration in New Zealand, the NZ government is commissioning a new 4,000 km, highquality 2D seismic data set with the intention of making it freely available to interested exploration companies by mid-2005.The very thick sedimentary succession, the presence of direct hydrocarbon indicators on seismic data, the strong gas shows in wells drilled offshore and the reasonable expectation of oil generation and expulsion into numerous large structures with good reservoir facies combine to make the offshore East Coast Basin an attractive exploration venue.
37
Roden, Rocky, Mike Forrest, Roger Holeywell, Matthew Carr, and P. A. Alexander. "The role of AVO in prospect risk assessment." Interpretation 2, no. 2 (May 1, 2014): SC61—SC76. http://dx.doi.org/10.1190/int-2013-0114.1.
Full textAbstract:
Essentially all companies exploring for oil and gas should perform a risk analysis to understand the uncertainties in their interpretations and to properly value order prospects in a company’s drilling portfolio. For conventional exploration in clastic environments, primarily sands encased in shales, a key component of the risk analysis process is evaluating direct hydrocarbon indicators, which can have a significant impact on the final risk value. We investigate the role AVO plays in the risk assessment process as a portion of a comprehensive and systematic DHI evaluation. Documentation of the geologic context and quantification of data quality and DHI characteristics, including AVO characteristics, is necessary to properly assess a prospect’s risk. A DHI consortium database of over 230 drilled prospects provides statistics to determine the importance of data quality elements, primarily in class 2 and 3 geologic settings. The most important AVO interpretation characteristics are also identified based on statistical results and correlated with well success rates. A significant conclusion is the relevance of AVO in risk analysis when it is the dominant component in the DHI portion of the risk. Critical in the risk assessment process is understanding the role AVO and DHI analysis play when prospects approach class 1 geologic settings. The impact that hydrocarbons have on the seismic response is significantly diminished in this setting versus the other AVO classes. All of these observations confirm the necessity of properly evaluating a prospect’s geologic setting and implementing a consistent and systematic risk analysis process including appropriate DHI and AVO components.
38
Попов, Олексій Денисович, Анатолій Іванович Долматов, and Володимир Федорович Сорокін. "Вплив промислових очищувальних рідин на анодно-окисне захисно-декоративне покриття отримане у розчині хромового ангідриду." Aerospace technic and technology, no. 4sup1 (August 27, 2021): 117–24. http://dx.doi.org/10.32620/aktt.2021.4sup1.16.
Full textAbstract:
The subject of research in this article is the anode-oxide coating of aluminum parts of the hull type of aircraft engine units and aircraft units under the influence of cleaning fluids of different nature and chemical compositions. The purpose of this work is to experimentally test, the effect of different cleaning fluids, under different operating conditions and on different equipment for the stability of the anode-oxide protective coating. Many experiments have been performed on three types of washing machines: jet and immersion washing machine, which works on all types of water-soluble detergents, washing machine cleaning in vacuum or low-pressure environment, uses modified alcohols or hydrocarbon solvents as a washing liquid, and specialized stand for cleaning parts with aviation kerosene, aviation fuel TS-1 or jet A-1. Flushing modes were, covered throughout the range of operation of this equipment. The operating conditions of engines and units and the need to use an anode-oxide coating of parts are determined. The main types of liquids for washing parts are considered. For each of the experiments a special technology of these studies was determined, as technological parameters, parameters that can change and affect the stability of the coating, were set the following temperature, detergent concentration, operating time, operating pressure in the detergent supply system. The change of each of these parameters was, carried out with the fixation of other technological parameters to determine the direct indicators of the impact of each of the parameters and to establish the growth of their impact on the anode-oxide coating. The conditions under which the coating is destroyed and the percentage of its damage from the total surface of the part are determined, and the quality of cleaning the part by particle size distribution and visual method was, also determined. It is determined that the greatest negative effects on the anodic oxide coating in the solution of chromic anhydride are acidic and alkaline water-soluble pore cleaning liquids, so they have the best quality of cleaning from contaminants, for which a range of indicators is determined at which the coating does not deteriorate.
39
Uruski, Chris, Callum Kennedy, Rupert Sutherland, Vaughan Stagpoole, and Stuart Henrys. "The discovery of a new sedimentary basin: offshore Raukumara, East Coast, North Island, New Zealand." APPEA Journal 48, no. 1 (2008): 53. http://dx.doi.org/10.1071/aj07006.
Full textAbstract:
The East Coast of North Island, New Zealand, is the site of subduction of the Pacific below the Australian plate, and, consequently, much of the basin is highly deformed. An exception is the Raukumara Sub-basin, which forms the northern end of the East Coast Basin and is relatively undeformed. It occupies a marine plain that extends to the north-northeast from the northern coast of the Raukumara Peninsula, reaching water depths of about 3,000 m, although much of the sub-basin lies within the 2,000 m isobath. The sub-basin is about 100 km across and has a roughly triangular plan, bounded by an east-west fault system in the south. It extends about 300 km to the northeast and is bounded to the east by the East Cape subduction ridge and to the west by the volcanic Kermadec Ridge. The northern seismic lines reveal a thickness of around 8 km increasing to 12–13 km in the south. Its stratigraphy consists of a fairly uniformly bedded basal section and an upper, more variable unit separated by a wedge of chaotically bedded material. In the absence of direct evidence from wells and samples, analogies are drawn with onshore geology, where older marine Cretaceous and Paleogene units are separated from a Neogene succession by an allochthonous series of thrust slices emplaced around the time of initiation of the modern plate boundary. The Raukumara Sub-basin is not easily classified. Its location is apparently that of a fore-arc basin along an ocean-to-ocean collision zone, although its sedimentary fill must have been derived chiefly from erosion of the New Zealand land mass. Its relative lack of deformation introduces questions about basin formation and petroleum potential. Although no commercial discoveries have been made in the East Coast Basin, known source rocks are of marine origin and are commonly oil prone, so there is good potential for oil as well as gas in the basin. New seismic data confirm the extent of the sub-basin and its considerable sedimentary thickness. The presence of potential trapping structures and direct hydrocarbon indicators suggest that the Raukumara Sub-basin may contain large volumes of oil and gas.
40
Soroka, B. S., and V. V. Horupa. "Environmental Characteristics of Modern Systems of Domestic Use of Fuel. Part 2. Pollutants Formation by Natural Gas Combustion in Atmospheric Burners: Experimental Studies." ENERGETIKA. Proceedings of CIS higher education institutions and power engineering associations 63, no. 5 (October 13, 2020): 450–61. http://dx.doi.org/10.21122/1029-7448-2020-63-5-450-461.
Full textAbstract:
The Gas Institute of the National Academy of Sciences of Ukraine performs comprehensive studies of the formation of toxic emissions in the flame of atmospheric burners and beyond the visible burning cones (“rich” primary flame). The experiments are based on the proven significant content of harmful substances in the combustion products of gas fuel in household appliances and on direct contact of consumers with gas emissions during the operation of the stoves. A methodology for the experimental researches of the harmful emissions formation has been proposed while the computerized firing rig serving as the diagnostic facility has been developed for studying the combustion of hydrocarbon gases in the burners of household stoves. Carbon oxides CO and nitrogen oxides NO and NO2 are considered as toxic emissions, while the primary air excess coefficient and the heat load of the burner are considered as variable parameters. Under operating conditions of a gas stove, its variable characteristics are the gas pressure in front of the nozzle of the atmospheric burner and its thermal power. When optimizing the design of burners, the determinant value of the stability of burning, energy and environmental indicators of fuel combustion is the coefficient of excess of primary air λpr at a given gas pressure before the burner. The influence of this coefficient on the formation of CO, NO, NO2 is established, and the possibility of emissions with a high concentration of nitrogen dioxide is proved. Since the concentration of [NO] decreases with an increase in λpr, and the absolute level of [NO2] concentrations is not significantly affected by the value of λpr, it is determined that the proportion of [NO2] concentration in the [NOx] = [NO] + [NO2] compound increases with an increase in the primary air excess coefficient.
41
Raeuchle, Sandra K., Douglas S. Hamilton, and M. Uzcátegui. "Integrating 3-D seismic imaging and seismic attribute analysis with genetic stratigraphy: Implications for infield reserve growth and field extension, Budare Field, Venezuela." GEOPHYSICS 62, no. 5 (September 1997): 1510–23. http://dx.doi.org/10.1190/1.1444254.
Full textAbstract:
Despite being a mature oil producer, the Budare Field in the Eastern Venezuela Basin offers considerable reserve growth potential because of stratigraphic and structural complexity. Our ability to resolve these complexities was enhanced following acquisition in 1995 of a 3-D seismic data set over a large part of the field. The seismic data were tied by synthetic to well‐log data by several wells having sonic and density information and then integrated with the high‐resolution genetic stratigraphic framework established from well‐log correlations. Two key surfaces identified on the seismic data correlated directly to two stratigraphically defined sequence boundaries, maximum flooding surfaces (MFS) 80 and 100. A third seismic surface correlated approximately with the stratigraphically defined MFS 62. Collectively, these surfaces form fundamental control surfaces from which seismic attribute analysis and imaging from inverse modeling were undertaken. Four depositional trends detected by the seismic imaging and attribute analysis have important implications for reserve growth potential, guiding future field development. An incised valley, filled primarily with thick fluvial sandstones, was detected by mapping average seismic amplitudes between the MFS 62 and 80 markers, and several step‐out drilling locations were identified where the sandstones intersect structurally high positions. The distribution of thick distributary‐mouth‐bar facies, and moreover, the boundary with adjacent thin‐bedded strandplain facies, were similarly detected by mapping average seismic amplitudes in a 35-ms time window below MFS 80. The mouth‐bar facies coincide with the crestal position of a potentially large, structurally defined field extension supporting multiple potential infill wells. Several high‐negative‐amplitude anomalies coinciding with thick fluvial sandstones overlying MFS 62 display faulted boundaries and are interpreted as direct hydrocarbon indicators, providing obvious infill drilling locations, and finally, a marine ravinement surface separating the key oil‐producing reservoirs below MFS 80 was identified by seismic inversion.
42
Yakymchuk, M. A., and I. M. Korchagin. "Hydrocarbons in the Gulf of Mexico: their genesis and extents of migration to the surface and to the atmosphere." Reports of the National Academy of Sciences of Ukraine, no. 11 (2020): 51–60. http://dx.doi.org/10.15407/dopovidi2020.11.051.
Full textAbstract:
The results of a reconnaissance survey of local areas, where a number of oil slicks are located in various regions of the Gulf of Mexico, are presented. Experimental studies using the direct-prospecting technology of frequency- resonance processing and the interpretation of satellite and photo images were carried out in order to study the features of the deep structure in the areas, where slicks are located. The results of instrumental measurements indicate that all nine survey sites in the Gulf are located above volcanoes, within which the synthesis of oil, condensate, and gas is carried out at the conditional border of 57 km. In the contours of such volcanoes, there are deep channels through which oil, condensate, and gas migrate to the upper horizons of the cross-section and can replenish the already formed deposits in hydrocarbon fields. In the absence of reliable seals over such channels, oil, condensate, and gas can migrate into the water column, and gas further into the atmosphere. During this migration, gas seeps are formed on the seabed and oil slicks on the water surface. The measurements confirmed the presence of all previously established types of volcanoes, in which conditions for the hydrocarbon synthesis exist at a depth of 57 km. These are volcanoes filled with 1) salt, 2) sedimentary rocks, 3) limestones, 4) granites, and 5) ultramafic rocks. Studies at the site near the emergency well indicate that there are a significant number of volcanoes in the Gulf, within which there are no conditions for the synthesis of hydrocarbons and amber. These are volcanoes filled with 1) dolomites, 2) marls, 3) siliceous rocks, as well as 4) basalts and 5) kimberlites. The additional evidence is obtained by instrumental measurements in favor of the deep (abiogenic) genesis of oil, condensate, and gas is of fundamental importance. Numerous facts of fixing the signals from oil, condensate, and gas at the conditional boundary of their synthesis of 57 km in the Gulf of Mexico and in other regions of the world allow us to make an assumption about the migration of abiogenic methane into the Earth’s atmosphere in colossal volumes! Methane seeps and oil slicks can serve as indicators of the activity of volcanoes in which hydrocarbons are synthesized. In these cases, drilling wells in the areas of the location of deep channels of the migration of abiogenic hydrocarbons to the upper horizons of the cross-section may be associated with great risks — with emergency situations during drilling.
43
Lisk, M., J. Ostby, N. J. Russell, and G. W. O’Brien. "OIL MIGRATION HISTORY OF THE OFFSHORE CANNING BASIN." APPEA Journal 40, no. 2 (2000): 133. http://dx.doi.org/10.1071/aj99069.
Full textAbstract:
The dual issues of the presence or absence of a viable, oil-prone petroleum system and reservoir quality represent key exploration uncertainties in the lightly explored Offshore Canning Basin, North West Shelf. To better quantify these factors, a detailed fluid inclusion investigation of potential reservoir horizons within the basin has been undertaken. The results have been integrated with regional petroleum geology and Synthetic Aperture Radar (SAR) oil seep data to better understand the oil migration risk in the region.The fluid inclusion data provide confirmation of widespread oil migration at multiple Mesozoic and Palaeozoic levels, including those wells that are remote from the likely source kitchens. The lack of evidence for present or palaeo-oil accumulations is consistent with the proposition that none of the currently water-wet wells appear to have tested a valid structure. These observations, when combined with the presence of numerous direct hydrocarbon indicators on seismic data and a number of oil slicks (from SAR data) at the basin’s edge, suggest that the potential for oil charge to valid structures is much higher than previously recognised.Petrographic analysis of the tight, gas-bearing, Triassic sandstones in Phoenix–1 suggests that the low porosity and permeability is the result of late poikilotopic carbonate cement. Significantly, the presence of oil inclusions within quartz overgrowths that pre-date the carbonate indicates that oil migration began prior to crystallisation of carbonate. Fluid inclusion palaeotemperatures combined with a 1D basin model suggest that trapping of oil as inclusions occurred in the Early to Middle Cretaceous and that predictions of reservoir quality using available water-wet wells could seriously under-estimate porositypermeability levels in potential traps that were charged with oil at about 100 Ma. Indeed, acid leaching of core plugs from Phoenix–1 indicates that removal of diagenetic carbonate results in significant permeability increase with obvious implications for the producibility of any future oil discovery. Further, evidence of Early Cretaceous oil charge has implications for the size and locality of source kitchens compared to that observed at the current day.Collectively, the data indicate the area has received widespread oil migration and suggest future exploration, even to relatively deep levels, may be successful if valid traps can be delineated.
44
Feder, Judy. "Who Is Winning in Energy Transition?" Journal of Petroleum Technology 73, no. 06 (June 1, 2021): 34–37. http://dx.doi.org/10.2118/0621-0034-jpt.
Full textAbstract:
We talk about “the energy transition” as if it were some type of unified, global event. Instead, numerous approaches to energy transitions are taking place in parallel, with all of the “players” moving at different paces, in different directions, and with different guiding philosophies. Which companies are best positioned to survive and thrive, and why? This article takes a look at what several top energy research and business intelligence firms are saying. What a Difference a Year Makes Prior to 2020—in fact, as recently as the 2014 bust that followed the shale boom—the oil and gas industry weathered downturns by “tightening their belts” and “doing more with less” in the form of cutting capital expenditures and costs, tapping credit lines, and improving operational efficiency. Adopting advanced digitalization and cognitive technologies as integral parts of the supply chain from 2015 to 2019 led to significant performance improvements as companies dealt with “shale shock.” Then, in 2020, a strange thing happened. Just as disruptive technologies like electric vehicles and solar photovoltaic and new batteries were gaining traction and decarbonization and environmental, social, and governance (ESG) issues were rising to the top of global social and policy agendas, COVID-19 left companies with almost nothing to squeeze from their supply chains, and budget cuts had a direct impact on operational performance and short-term operational plans. To stabilize their returns, many oil and gas companies revised and reshaped their portfolios and business strategies around decarbonization and alternative energy sources. The result: The investment in efforts toward effecting energy transition surpassed $500 billion for the first time in early 2021 ($501.3 billion, a 9% increase over 2019, according to BloombergNEF) despite the economic disruption caused by COVID-19. According to Wood Mackenzie, carbon emissions and carbon intensity are now key metrics in any project’s final investment decision. And, Rystad Energy said that greenhouse-gas emissions are declining faster than what is outlined in many conventional models regarded as aggressive scenarios. In Rystad’s model, electrification levels will reach 80% by 2050. A Look at the Playing Field: Energy Transition Pillars In a February 2021 webinar, Rystad discussed what leading exploration and production (E&P) companies are doing to keep up with the energy transition and stay investable in the rapidly changing market environment. The consulting firm researched the top 25 E&P companies based on their oil and gas production in 2020 and analyzed how they approach various market criteria in “three pillars of energy transition in the E&P sector” that the firm regards as key distinguishers and important indicators of potential success (Fig. 1). The research excludes national oil companies (NOCs) except for those with international activity (INOCs). Rystad says these 25 companies are responsible for almost 40% of global hydrocarbon production and the same share of global E&P investments and believes the trends within this peer group are representative on a global scale.
45
Hughes, J. K. "Examination of Seismic Repeatability as a Key Element of Time-Lapse Seismic Monitoring." SPE Reservoir Evaluation & Engineering 3, no. 06 (December 1, 2000): 517–24. http://dx.doi.org/10.2118/68246-pa.
Full textAbstract:
Summary The propagation of elastic waves in rocks is determined by the bulk modulus, shear modulus, and bulk density of the rock. In porous rocks all these properties are affected by the distribution of pore space, the geometry and interconnectivity of the pores, and the nature of the fluid occupying the pore space. In addition, the bulk and shear moduli are also affected by the effective pressure, which is equivalent to the difference between the confining (or lithostatic) pressure and pore pressure. During production of hydrocarbons from a reservoir, the movement of fluids and changes in pore pressure may contribute to a significant change in the elastic moduli and bulk density of the reservoir rocks. This phenomenon is the basis for reservoir monitoring by repeated seismic (or time-lapse) surveys whereby the difference in seismic response during the lifetime of the field can be directly related to changes in the pore fluids and/or pore pressure. Under suitable conditions, these changes in the reservoir during production can be quantitatively estimated by appropriate repeat three-dimensional (3D) seismic surveys which can contribute to understanding of the reservoir model away from the wells. The benefit to reservoir management is a better flow model which incorporates the information derived from the seismic data. What are suitable conditions? There are two primary factors which determine whether the reservoir changes we wish to observe will be detectable in the seismic data:the magnitude of the change in the elastic moduli (and bulk density) of the reservoir rocks as a result of fluid displacement, pressure changes, etc.;the magnitude of the repeatability errors between time-lapse seismic surveys. This includes errors associated with seismic data collection, ambient noise and data processing. The first is the signal component and the second the noise component. Previous reviews of seismic monitoring suggest that for 3D seismic surveys a signal-to-noise (S/N) ratio of 1.0 is sufficient for qualitative estimation of reservoir changes. Higher S/N ratios may allow quantitative estimates. After a brief examination of the rock physics affecting the seismic signal, we examine the second factor, repeatability errors, and use a synthetic seismic model to illustrate some of the factors which contribute to repeatability error. We also use two land 3D surveys over a Middle East carbonate reservoir to illustrate seismic repeatability. The study finds that repeatability errors, while always larger than desired, are generally within limits which will allow production-induced changes in seismic reflectivity to be confidently detected. Introduction Seismic data have been used successfully for many decades in the petroleum industry and have contributed significantly to the discovery of new fields throughout the world. Initially, seismic surveys were primarily an exploration tool, assisting in the identification of potential hydrocarbon structural and stratigraphic traps for drilling targets. With the introduction of 3D seismic surveys in the 1970's, accurate geological structural mapping became possible while the use of new seismic attributes as hydrocarbon indicators improved the success rate of discovery wells. More recently seismic data have also contributed to a better reservoir description away from the wells by making use of the correlation between suitable seismic attributes and petrophysical quantities such as porosity and net to gross, and by incorporating robust geostatistical methods for estimating the static reservoir model. Better seismic acquisition technology, improved seismic processing methods and an overall improvement in signal to noise have led to further 3D seismic surveys over producing fields primarily for better imaging of the reservoir and improved reservoir characterization. The concept of using repeated seismic surveys (time-lapse seismic) for monitoring changes in the reservoir due to production was suggested in the 1980's,1-3 and early tests were done by Arco in the Holt Sand fireflood4 from 1981-83. Over the last few years, the number of publications relating to time-lapse seismic [often referred to as four-dimensional (4D) seismic] has increased dramatically. Prior to time-lapse seismic monitoring, seismic data have been the domain of geologists and geophysicists, but the possibility of monitoring fluid displacements and pressure changes in a producing reservoir, away from the wells, has direct relevance to reservoir engineers and reservoir management. More exciting possibilities have been introduced by the use of time-lapse seismic data in combination with production history matching5 for greater refinement in optimization of the reservoir model. It is important, however, that reliable criteria are used to assess the feasibility of seismic monitoring.6
46
Barton, Colleen A., and Mark D. Zoback. "Discrimination of Natural Fractures From Drilling-Induced Wellbore Failures in Wellbore Image Data - Implications for Reservoir Permeability." SPE Reservoir Evaluation & Engineering 5, no. 03 (June 1, 2002): 249–54. http://dx.doi.org/10.2118/78599-pa.
Full textAbstract:
Summary Natural fractures and drilling-induced wellbore failures provide critical constraints on the state of in-situ stress and the direct applicability to problems of reservoir production, hydrocarbon migration, and wellbore stability. Acoustic, electrical, and optical wellbore images provide the means to detect and characterize natural fracture systems and to distinguish them from induced wellbore failures. We present new techniques and criteria to measure and characterize attributes of natural and induced fractures in borehole image data. These techniques are applied to the characterization of fracture permeability in two case studies. Introduction Wellbore image logs are extremely useful for identifying and studying a variety of modes of stress-induced wellbore failures. We present examples of how these wellbore failures appear in different types of image data and how they can be discriminated from natural fractures that intersect the wellbore. We then present brief overviews of two studies, which illustrate how the techniques have been applied to address specific issues of fracture permeability. Drilling-induced failures are ubiquitous in oil and gas and geothermal wells because the process of drilling a well causes a concentration of the far-field tectonic stress close to the wellbore, which often can exceed rock strength. Through the use of wellbore imaging and other logging techniques, stress-induced failures can be detected and categorized (compressive, tensile, or shear) and then used to estimate the unknown components of the stress field. We demonstrate how these modes of wellbore failures appear in different types of image data and the pitfalls in their interpretations. The most valuable use of drilling-induced features is to constrain the orientations and magnitudes of the current stress field. The use of drilling-induced features as stress indicators has become routine in the oil and gas industry.1–8 The detection of these features at the wellbore wall has become a primary target for Logging While Drilling/Measurement While Drilling (LWD/ MWD) real-time operations.9 A strong correlation between critically stressed fractures (fractures optimally oriented to the stress field for frictional failure) and hydraulic conductivity has been documented in a variety of reservoirs worldwide.10–12 When faults are critically stressed, permeabilities are increased, and the movement of fluid along faults is possible. We present examples of how knowledge of the stress state and natural fracture population may be used to access reservoir permeability. Drilling-Induced Tensile Wall Fractures Compressive and tensile failure of a wellbore is a direct result of the stress concentration around the wellbore, which results from drilling a well into an already stressed rock mass.13 Compressive wellbore failures (wellbore breakouts), first identified with caliper data, are useful for determining stress orientation in vertical wells.14–16 The study of such features with acoustic and electrical imaging devices makes it possible to clearly identify such features and to use them to determine stress magnitude and stress orientation.15,17–19 It is well known that if a wellbore is pressurized, a hydraulic fracture will form at the azimuth of the maximum horizontal stress.20 The formation of drilling-induced tensile wall fractures is the result of the natural stress state, perhaps aided by drilling-related perturbations, that causes the wellbore wall to fail in tension. The general case of tensile and compressive failure of arbitrarily inclined wellbores in different stress fields is described by Peska and Zoback,1 who demonstrate that there is a wide range of stress conditions under which drilling-induced tensile fractures occur in wellbores, even without a significant wellbore-fluid overpressure. We call these fractures tensile wall fractures because they occur only in the wellbore wall as a result of the stress concentration. These failures form in an orientation of the maximum principal horizontal stress in a vertical borehole (Fig. 1a) and as en echelon features in deviated wells (Fig. 1b). Because drilling-induced tensile wall fractures are very sensitive to the in-situ stress, they can be used to constrain the present state of stress.1,2,21–23 Pitfalls in Interpretation of Tensile Wall Fractures in Wellbore Image Data In cases in which drilling-induced tensile fractures form at an angle to the wellbore axis, it can be difficult to distinguish them from natural fractures, especially in electrical image logs that do not sample the entire wellbore circumference. Because misinterpretation of such features could lead to serious errors in the characterization of a fractured (or possibly not fractured!) reservoir, as well as the assessment of in-situ stress orientation and magnitude, we present criteria that are useful for discriminating natural from induced tensile fractures when observed in wellbore image logs. This is especially important because the wellbore stress concentration can have a significant effect on the appearance of natural fractures that intersect the wellbore. It is well known that fractures are mechanically weakened at their intersection with the borehole. This erosion causes the upper and lower peak and trough of the fracture sinusoid to be enlarged and subsequently enhanced in the standard 2D unwrapped view of wellbore image data (Fig. 2). Where the borehole hoop stress is tensile, the intersection of a natural fracture or foliation plane with the tensile region of the borehole may be preferentially opened in tension (Fig. 3a). These drilling-enhanced natural fractures can be mistaken easily for inclined tensile wellbore failures (Fig. 1b), thus resulting in serious errors in geomechanical modeling. Incipient wellbore breakouts are the early stages of wellbore breakout development, in which the borehole compressive stress concentration has exceeded the rock strength and initiated breakout development. The failed material within the breakout, however, has not yet spalled into the borehole (Fig. 3b). In a vertical borehole, these failures may appear as thin "fractures" that propagate vertically in the borehole and may be confused with drilling induced tensile wall cracks.
47
JPT staff, _. "E&P Notes (December 2020)." Journal of Petroleum Technology 72, no. 12 (December 1, 2020): 16–17. http://dx.doi.org/10.2118/1220-0016-jpt.
Full textAbstract:
China Shale-Gas Field Sets Production Record Sinopec recorded China’s highest daily output of shale gas at 20.62 million cubic meters (Mcm) at its Fuling shale-gas field in Chongqing, China, a key gas source for the Sichuan-East gas pipeline. The first major commercial shale-gas project in China, Fuling has continuously broken records for the shortest gasfield drilling cycle while significantly increasing the drilling of high-quality reservoirs covering more than 3 million m, according to Sinopec. Gasfield production construction was also expanded to raise production capacity. The company said the field maintains a daily output of 20 Mcm, producing an estimated 6.7 Bcm per year. Apache and Total Plan Suriname Appraisals Apache filed appraisal plans for its Maka and Sapakara oil discoveries in block 58 offshore Suriname. The company said another submission is expected for Kwaskwasi, the largest find in the block, by the end of the year. Operations continue for Keskesi, the fourth exploration target. There are plans to drill a fifth prospect at Bonboni in the North-Central portion of the concession. Partner company Total is assuming operatorship of the block ahead of next year’s campaigns. BP Emerges as Sole Bid for Offshore Canada Parcels BP was the only operator to place a bid in the Canada-Newfoundland and Labrador Offshore Petroleum Board (C-NLOPB) Call for Bids NL20-CFB01, which offered 17 parcels (4,170,509 hectares) in the eastern Newfoundland region. The successful bid was for Parcel 9 (covering 264,500 hectares) for $27 million in work commitments from BP Canada Energy Group. Subject to BP satisfying specified requirements and receiving government approval, the exploration license will be issued in January 2021. No bids were received for the remaining 16 parcels, which may be reposted in a future Call for Bids. Criteria for selecting a winning bid is the total amount the bidder commits to spend on exploration of the parcel during the first period of a 9-year license, with a minimum acceptable bid of $10 million in work commitments for each parcel. Beach Energy To Drill Otway Basin Well Beach Energy plans to drill at its Artisan-1 well about 32 km offshore Victoria, Australia, in the Otway basin, before the end of 2021. The well, located on Block Vic/P43, was to be spudded in 1H 2020 but was delayed due to COVID-19. The timeframe for drilling was confirmed by the National Offshore Petroleum Safety and Environmental Management Authority, which also said Beach is keeping open the option to suspend the well and develop it, pending reservoir analysis. Anchors, mooring chains, and surface buoys have already been laid for the well, which is in a water depth of approximately 71 m. The well is expected to take approximately 35–55 days to drill, depending on the final work program and potential operational delays. Diamond Offshore’s semisubmersible Ocean Onyx was contracted for the drilling program. Artisan is the first of Beach’s planned multiwell campaigns, which also include development wells at the Geographe and Thylacine fields. Hess Completes Sale of Interest in Gulf of Mexico Field Hess completed the sale of its 28% working interest in the Shenzi Field in the deepwater Gulf of Mexico (GOM) to BHP, the field’s operator, for $505 million. Shenzi is a six-lease development structured as a joint ownership: BHP (operator, 44%), Hess (28%), and Repsol (28%). The acquisition would bring BHP’s working interest to 72%, adding approximately 11,000 BOE/D of production (90% oil). The sale is expected to close by December 2020. Hess CEO John Hess said proceeds from the sale will help fund the company’s investment in Guyana. Greenland Opens New Offshore Areas Greenland opened three new offshore areas for application of oil and gas exploitation licenses off West Greenland. The areas are Baffin Bay, Disko West, and Davis Strait. The country also said it is working on an oil strategy to reduce geological uncertainty by offering an investment package to companies that engage in its Open Door Procedures. The procedures are a first-mover advantage to remove national oil company Nunaoil, as a carried partner, reducing turnover and surplus royalties. It is estimated to reduce the government take by 51.3% to 40.6%. Shell and Impact Oil & Gas Agree to South Africa Farmout Africa Oil announced Impact Oil & Gas entered into two agreements for exploration areas offshore South Africa. The company has a 31.10% share-holding in Impact, a privately owned exploration company. Impact entered into an agreement with BG International, a Shell subsidiary, for the farm-out of a 50% working interest and operatorship in the Transkei and Algoa exploration rights. Shell was also granted the option to acquire an additional 5% working interest should the joint venture (JV) elect to move into the third renewal period, expected in 2024. Algoa is located in the South Outeniqua Basin, east of Block 11B/12B, containing the Brulpadda gas condensate discovery and where Total recently discovered gas condensate. The Transkei block is northeast of Algoa in the Natal Trough Basin where Impact has identified highly material prospectivity associated with several large submarine fan bodies, which the JV will explore with 3D seismic data and then potential exploratory drilling. Impact and Shell plan to acquire over 6,000 km² of 3D seismic data during the first available seismic window following completion of the transaction. This window is expected to be in the Q1 2022. After the closing of the deal, Shell will hold a 50% interest as the operator and Impact will hold 50%. Impact also entered into an agreement with Silver Wave Energy for the farm-in of a 90% working interest and operatorship of Area 2, offshore South Africa. East and adjacent to Impact’s Transkei and Algoa blocks, Area 2 complements Impact’s existing position by extending the entire length of the ultradeepwater part of the Transkei margin. Together, the Transkei and Algoa Blocks and Area 2 cover over 124,000 km2. Area 2 has been opened by the Brulpadda and Luiperd discoveries in the Outeniqua Basin and will be further tested during 2021 by the well on the giant Venus prospect in ultradeepwater Namibia, where Impact is a partner. Impact believes there is good evidence for this Southern African Aptian play to have a common world-class Lower Cretaceous source rock, similar excellent-quality Apto-Albian reservoir sands, and a geological setting suitable for the formation of large stratigraphic traps. Following completion of the farm-in, Impact will hold 90% interest and serve as the operator; Silver Wave will hold 10%. Petronas Awards Sarawak Contract to Seismic Consortium The seismic consortium comprising PGS, TGS, and WesternGeco was awarded a multiyear contract by Petronas to acquire and process up to 105,000 km2 of multisensor, multiclient 3D data in the Sarawak Basin, offshore Malaysia. The contract award follows an ongoing campaign by the consortium in the Sabah offshore region, awarded in 2016, in which over 50,000 km2 of high-quality 3D seismic data have been acquired and licensed to the oil and gas industry to support Malaysia license round and exploration activity. The Sarawak award will allow for a multiphase program to promote exploration efforts in the prolific Sarawak East Natuna Basin (Deepwater North Luconia and West Luconia Province). The consortium is planning the initial phases and is engaging with the oil and gas industry to secure prefunding ahead of planned acquisition, covering both open blocks and areas of existing farm-in opportunities. Total Discovers Second Gas Condensate in South Africa Total made a significant second gas condensate discovery on the Luiperd prospect, located on Block 11B/12B in the Outeniqua Basin, 175 km off the southern coast of South Africa. The discovery follows the adjacent play-opening Brulpadda discovery in 2019. The Luiperd-1X well was drilled to a total depth of about 3,400 m and encountered 73 m of net gas condensate pay in well-developed, good-quality Lower Cretaceous reservoirs. Following a coring and logging program, the well will be tested to assess the dynamic reservoir characteristics and deliverability. The Block 11B/12B covers an area of 19,000 km2, with water depths ranging from 200 to 1800 m. It is operated by Total with a 45% working interest, alongside Qatar Petroleum (25%), CNR International (20%), and Main Street, a South African consortium (10%). The Luiperd prospect is the second to be drilled in a series of five large submarine fan prospects with direct hydrocarbon indicators defined utilizing 2D and 3D seismic data. BP Gas Field Offshore Egypt Begins Production BP started gas production from its Qattameya gasfield development offshore Egypt in the North Damietta offshore concession. Through BP’s joint venture Pharaonic Petroleum Company working with state-owned Egyptian Natural Gas Holding Co., the field, which is expected to produce up to 50 MMcf/D, was developed through a one-well subsea development and tieback to existing infrastructure. Qattameya, whose discovery was announced in 2017, is located approximately 45 km west of the Ha’py platform, in 108 m of water. It is tied back to the Ha’py and Tuart field development via a new 50-km pipeline and connected to existing subsea utilities via a 50-km umbilical. BP holds 100% equity in the North Damietta offshore concession in the East Nile Delta. Gas production from the field is directed to Egypt’s national grid.
48
Alsouki, Mohammad, Najeh Alali, and Mustafa M. Alfaize. "The Seismic Image of The Direct Hydrocarbon Indicators in Offshore Syria." Iraqi Journal of Science, January 26, 2020, 112–26. http://dx.doi.org/10.24996/ijs.2020.61.1.12.
Full textAbstract:
The easternmost Mediterranean Basin is a candidate to be one of the most important hydrocarbon regions in the world, especially after significant gas discoveries in Levantine Basin in 2009. Offshore Syria is one of the easternmost Mediterranean areas which is still an unexplored virgin area. The seismic interpretation results of the study area showed encouraging evidences of considerable hydrocarbon accumulations within different sedimentary successions, which are Direct Hydrocarbon Indicators (DHIs). Indicators such as reflectivity anomalies (flat spots and dim spots) and polarity reversal were found within significant structural highs of Tertiary or/Late Cretaceous and Early Jurassic successions. Also, gas chimney and a lot of bright spots were observed within a Plio-Pleistocene succession above tops and flanks of Messinian Salt diapirs and pinch-outs.
The seismic attributes such as instantaneous frequency and phase and reflection strengths were used in this study to improve the seismic interpretation image in the gas-affected area, with the purpose of exhibiting strong amplitude abnormalities and confirming the occurrence of a polarity reversal and the low frequencies within and below some of the structural anticlines. These attributes suggest that there are potential hydrocarbon reservoirs.
49
Kurt, Rudolph; Fahmy, William; Stob. "Abstract: Direct Hydrocarbon Indicators: Exxons Worldwide Experience." AAPG Bulletin 82 (1998) (1998). http://dx.doi.org/10.1306/00aa7ae0-1730-11d7-8645000102c1865d.
Full text
50
Blom, F., and M. Bacon. "Application of direct hydrocarbon indicators for exploration in a Permian-Triassic play, offshore the Netherlands." First Break 27, no. 1297 (March 1, 2009). http://dx.doi.org/10.3997/1365-2397.2009005.
Full text