Abstract A soil-gas survey was conducted in the Kotcho-Kyklo area of northeast British Columbia, with the objective to test for, evaluate, and verify methane-seep patterns that could provide critical exploration information on deep (about 1990 m) Devonian reef complexes in the Slave Point and Keg River Formations. Survey conditions were difficult from both a surface-topography and a subsurface point of view. First, the terrain is partial muskeg, with pervasive in-situ soil-gas generation and therefore the potential for masking or confusing surface-seep signals. Second, multiple gas-bearing horizons are present above the deep reefs, with the potential for confusion regarding seep-signal origin. Third, the region is dry-gas-bearing, with little or no compositional reservoir contrast. High-quality soil-gas sampling and analysis, coupled with advanced vector analysis to reconstruct and explain soil-gas data in terms of source-gas families, allow us to recognize and numerically reconstruct a distinct group of surface methane-seep samples that are compositionally consistent with reservoir gases and that correspond to the deep reefs. As a result of this numerical evaluation effort, a tentative seismic anomaly was evaluated geochemically, resulting in a lower exploration drilling risk and a subsequent reef discovery. Based on numerical analysis, three types of surface-methane samples can be discriminated. Soil-gas samples having very high methane content and essentially pure seep-methane portions are clearly related to Devonian gas pools. These very high methane contents, coupled with very high seep-methane portions in the samples, are apparently the cumulative effect of combined seepage from deeper and shallower horizons, facilitated and amplified along sediment drape features over Keg River reefs. A second group of methane samples is high in methane content, with medium to high seep-methane portions, a result of regional methane seepage from pervasive, shallower gas horizons and mixed with methane contributions from biological activity. This group is not related to the deep reef structures. A third group is relatively low in methane content, with low to marginal seep-methane portions. A comparison of total methane content with seep-methane portions indicates that in fact, high methane concentrations are driven by seepage and are not biologically derived methane, which often is pervasive in wet and swampy environments. In addition, numerical evidence is provided indicating that ethane and higher alkanes present in the soil-gas samples are not related to seepage. The migration pathway of gases to the surface is nearly vertical and appears to be amplified and focused along the sediment drape features over the reefs. Assuming that some of the fracture network is associated with the drape features, this would explain the exceptional seepage rates over the reefs and the tight clustering of reef-related seep samples at the surface over these reef structures. The case study presented here stresses the argument for requiring the data processing of usually noisy soil hydrocarbon gas data to isolate a distinct seep signal and to classify information contained in these surface gas data.

Abstract A soil-gas survey was conducted over a number of prospects in the plains (“llanos”) and the Andean foothills regions in the Barinas-Apure Basin of western Venezuela. Initial attempts to numerically distinguish a seep-gas signal from background gases failed. Basic statistics allow only a tenuous differentiation between background gases and possible seep-gas populations having slightly anomalous hydrocarbon-gas concentrations. Further data processing on this specific population using advanced vector analysis facilitated the discrimination within a variety of soil-gas sources and distinguished suites of samples with weak, seepage-related surface-gas patterns that resemble normal condensate/wet-gas sources at depth. An important observation from this surface geochemical program was the presence of a condensate/wet-gas trend in the foothills, confirming subsurface geochemical model predictions of the existence of wet reservoir gases in this area. Plots of the distribution of the various soil-gas sample suites on base maps of identified exploratory prospects show distinct clustering of seepage-related sample suites over areas with structural highs. Further scrutiny of the distribution of these “geochemical exploration leads” (GEL anomalies), in terms of coincidence with oil-productive areas, reveals that the GEL anomalies occur predominantly over now-productive wells. This observation also prompted the reevaluation of an old well recently associated with a surface GEL anomaly but originally abandoned and classified as dry in the 1930s. Reinterpretation of the well-log information now indicates 30 m of net pay in sandy reservoirs. Future drilling should provide more information on the extent and impact of this surface-gas technology on exploration decision making and risk analysis. Overall, the active seepage in the two work areas is relatively weak, although higher levels are observed in the foothills region because of favorable gas/oil ratios (GORs), normal reservoir pressure, and intense tectonic fracturing. These factors provide more favorable vertical or near-vertical gas migration than occurs in the plains region, where low GORs, reservoir underpressure, and less intense tectonic fracturing diminish vertical migration. In addition, initial (presurvey) concerns of intense in-situ biological soil-gas formation in a tropical environment, which would mask or diminish possible seep signals at the surface, could be resolved: Deep soil-gas sampling below a shallow zone of intense soil microbial activity, in combination with numerical surface-gas data processing, permits recognition and evaluation of subtle surface-seep trends in the area.

Abstract In Western Canada, and probably elsewhere around the world, “magnetically enhanced zones” above microseeping hydrocarbon reservoirs can exhibit distinctive magnetic signatures that are characteristic of the reservoir. These distinctive magnetic signatures have proven to be invaluable for hydrocarbon exploration, and we have achieved 85% exploration success using ground-based magnetic and radiometric techniques in Western Canada. Differences in timing and duration of microseepage and differences in composition and pressure of the microseeping hydrocarbon gases from separate petroleum systems probably control the magnetic mineralogy, magnetic grain-size distributions, magnetic susceptibility, and natural remanent magnetization (NRM) directions in the magnetically enhanced zones. Together, these differences can yield diagnostic “residual” (remanent + induced) short-spatial-wavelength magnetic anomalies above different reservoirs. Whereas our magnetic surveys are measuring fossil anomalies at depths of about 150 m, our radiometric surveys are measuring modern geochemical alterations at depths <25 cm. Thus, finding both magnetic and radiometric anomalies at the same location implies not only that a microseeping hydrocarbon reservoir once existed below, but also that it is still there and still leaking. In this study, we present six case histories from Western Canada in which our combined magnetic and radiometric surveys were effective for hydrocarbon exploration. Our high-resolution ground-magnetic (HRGM) surveys have sufficiently high resolution that residual magnetic anomalies commonly appear to be dipolar in Western Canada. Nearly equal intensities for the positive and negative lobes of the anomalies, and major departure of the dipole axes from present magnetic north, imply that (1) about half the intensity of the residual anomalies represents remanent, rather than induced, magnetization; and (2) a significant proportion of the remanent magnetization is “reversed polarity” and hence is older than the most recent geomagnetic reversal at 0.78 Ma. In the prolific Devonian reservoirs of Western Canada, much of the reversed-polarity magnetization probably dates from a strong “reversed-polarity-bias interval” that prevailed during the early Tertiary, from 63 to 41 Ma. At that time, generation of hydrocarbons, rapid subsidence, and the regional topographic hydrodynamic drive created high pore pressures that facilitated regional vertical fracturing of the Laramide foreland. Above reservoirs where oil was trapped during early Tertiary migration, buoyant hydrocarbon microbubbles began to rise along the regional, vertical microfractures. At higher structural levels, the microseeping hydrocarbons caused magnetic minerals to precipitate (by inorganic and/or biogenic processes) in magnetically enhanced zones, thereby recording early Tertiary, reversed-polarity remanent magnetization. Later in the Tertiary, a second generation of magnetically enhanced zones probably was created after maximum burial, at peak overpressure, and when methane began to exsolve by pressure reduction during isostatic uplift. In Western Canada, the strongest HRGM anomalies occur above the deepest, most prolific reservoirs at the highest pressures, and the weakest HRGM anomalies occur above shallower, less-productive reservoirs at lower pressures. In the Alberta Basin, the HRGM anomaly intensity decreases monotonically, from highest values over prolific Leduc Formation (Upper Devonian) pinnacle-reef reservoirs, to somewhat lower values over Nisku Formation (Upper Devonian) biostrome reservoirs, to still lower values over less-productive Cretaceous blanket/channel-sand reservoirs, to lowest values over dry and abandoned (D&A) wells. In the Williston Basin, strong HRGM anomalies occur above Mission Canyon Formation (Mississippian) limestone cuesta reservoirs, whereas no HRGM anomalies (only radiometric anomalies) occur above shallower lower Amaranth Formation (Triassic?) channel-sand reservoirs. The stronger HRGM anomalies above the deeper Devonian and Mississippian reservoirs may reflect (1) higher concentrations of authigenic magnetic minerals in the magnetically enhanced zones; (2) more focusing of vertically ascending microbubbles by the more nearly point-source pinnacle reef and cuesta reservoirs, compared with more spatially diffuse blanket/channel-sand reservoirs; and (3) shallower depths of magnetically enhanced zones as a result of higher pressure within the deeper reservoirs. For hydrocarbon exploration, the distinctive magnetic signatures revealed by high-resolution ground-magnetic surveys have an important practical application: We find that the HRGM anomaly intensity and the residual magnetic-anomaly azimuth can identify the reservoir that is causing the anomaly. We illustrate this principle in three case histories in the Williston Basin and three case histories in the Alberta Basin. Although all six of these case histories are from Western Canada, ground-magnetic surveys would probably be equally successful worldwide, especially where hydrocarbon microseepage has occurred during the Tertiary (65 to 1.8 Ma), when the geomagnetic field exhibited reversed-polarity bias. Case histories 1 and 2 document three new oil-field discoveries, based on magnetic and/or radiometric anomalies over lower Amaranth and Mission Canyon reservoirs near Pierson, Manitoba. Case history 3, at the Waskada field, Manitoba, is an after-drilling study, in which the HRGM survey delineates Mission Canyon limestone reservoirs and the radiometric survey delineates productive channels in the overlying lower Amaranth sand. Case history 4, another after-drilling study, documents that an HRGM survey and a 3-D seismic survey are equally effective in targeting a Leduc pinnacle reef at the Rumsey field, Alberta. Case histories 5 and 6 cover 10 4 ha in central Alberta, including 55 Cretaceous producers, 15 Nisku producers, and 22 abandoned wells. After-drilling comparison of the magnetic data with the production data reveals that the HRGM surveys could have been used to predict the producers and to avoid the dry holes. Statistical comparisons of high-resolution ground-magnetic (HRGM) with high-resolution aeromagnetic (HRAM) data and verification with ground data of a specific HRAM anomaly in central Alberta reveal that airborne and ground-magnetic surveys can be used together, cost-effectively, for hydrocarbon exploration. Reconnaissance HRAM surveys are especially useful in targeting prospects for further, more-detailed evaluation by HRGM/radiometric surveys. In Western Canada, combined HRGM and concurrent radiometric surveys have been highly successful in finding hydrocarbons, and the total cost, including permitting, is about 20% the cost of a 3-D seismic survey over the same area. These surveys complement traditional exploration methods, substantially reduce finding costs, and significantly increase the probability of exploration success.

Abstract The successful application of surface and nearsurface geochemical techniques in hydrocarbon exploration requires careful integration of many geological disciplines. Surface geochemistry can provide the explorationist with a means to screen large areas rapidly, economically, and qualitatively for overall petroleum source potential. Regions of favorable thermal environments for the formation of petroleum can be defined by identifying areas containing thermogenic hydrocarbons in soilgas. Soilgas techniques are also useful in determining areas of prospective accumulations prior to conducting additional and more costly exploration programs. Historically, the presence of an active oil or gas seep was sufficient to deem an area as prospective. Seep detection today rarely involves visible evidence of hydrocarbons; rather, it deals with seeps of extremely small magnitude (microseeps) that are not directly visible to the unaided eye. Typically, microseeps are detectable through the use of sensitive analytical instrumentation. In addition, it may be possible to detect active or inactive microseepage from its secondary manifestations such as bleaching of rocks in the area of the seep, the presence of stressed vegetation, or the formation of authigenic magnetite. Examples of some of these secondary indicators can be found in studies conducted by Dalziel and Donovan (1980), Donovan (1974), and Furguson (1975). Interpretation of these secondary indicators is often difficult because other natural processes can produce the same physicochemical features. Furthermore, the quantity and composition of hydrocarbon gases in the soil may be affected by the local geology. Consequently, the true meaning and character of these microseeps can only be realized after

Abstract Research studies based on foreland basins (mainly in eastern Colorado) examined three surface geochemical exploration (SGE) methods as possible hydrocarbon (HC) exploration techniques. The first method, microbial soil surveying, has high potential as an exploration tool, especially in development and enhanced recovery operations. Integrative adsorption, the second technique, is not effective as a quantitative SGE method because water, carbon dioxide, nitrous oxide, unsaturated hydrocarbons, and organic compounds are collected by the adsorbent (activated charcoal) much more strongly than covalently bonded microseeping C 1 –C 5 thermogenic HCs. Qualitative comparisons (pattern recognition) of C 8+ mass spectra cannot gauge HC gas microseepage that involves only the C 1 –C 5 HCs. The third method, soil calcite surveying, also has no potential as an exploration tool. Soil calcite concentrations had patterns with pronounced areal contrasts, but these patterns had no geometric relationship to surface traces of established or potential production, that is, the patterns were random. Microscopic examination of thousands of soils revealed that soil calcite was an uncrystallized caliche coating soil particles. During its precipitation, caliche captures or occludes any gases, elements, or compounds in its immediate vicinity. Thus, increased signal intensity of some SGE methods should depend on increasing soil calcite concentrations. Analyses substantiate this hypothesis. Because soil calcite has no utility as a surface exploration tool, any surface method that depends on soil calcite has a diminished utility as an SGE tool. Isotopic analyses of soil calcites revealed carbonate carbon 5 13 C values of −4.0 to +2.0‰ (indicating a strong influence of atmospheric CO 2 ) as opposed to expected values of −45 to −30‰ if the carbonate carbon had originated from microbial oxidation of microseeping HC gases. These analyses confirm a surface origin for this soil calcite (caliche), which is not necessarily related to HC gas microseepage. This previously unappreciated pivotal role of caliche is hypothesized to contribute significantly to the poor and inconsistent results of some SGE methods.

Abstract In the last 50 years, surface geochemical detection of microseeps has gained credibility as a viable petroleum exploration tool. Traces of organic compounds measured in the near-surface sediments provide a rapid and inexpensive method for diagnosing the probable hydrocarbon content of potential trapping features that have been delineated in the subsurface by seismic methods. Light-hydrocarbon yield, composition, fluorometric-intensity, and magnetic-susceptibility data obtained from analysis of seafloor samples were used to estimate the fluid contents of potential reservoirs defined by more conventional exploration methods in the Zaafarana and North Zaafarana concessions in the Gulf of Suez. Acid-released gas yields, compositions, and relative fluorometric intensities indicate that the area is one in which active petroleum generation is occurring. Mapped acid-released-gas, fluorometric-intensity, and magnetic-susceptibility patterns are concordant and coincide with major structural features and generating basins. Local geochemical disturbances near the surface coincide with structural targets that have been defined in the subsurface by seismic methods. Detailed analysis of these disturbed areas demonstrates that subtle differences can be observed. Drilling results from wells drilled in several of these areas after completion of this study demonstrate that these differences represent the surface expression of reservoired hydrocarbons and the leakage of hydrocarbons from the hydrodynamic system, as seen at the surface. This study demonstrates the necessity of carefully integrating data from several surface geochemical methods with data obtained by more conventional exploration methods. We believe that surface hydrocarbon-exploration techniques, when prudently integrated with conventional subsurface tools such as seismic and geologic analysis, can be used to high-grade drilling targets and ultimately to reduce exploration risk.

Abstract Hydrocarbon seeps in surficial marine sediments are of two types: active and passive. Active seeps occur where gas bubbles, pockmarks, or bright spots are visible on seismic profiles and where chemosynthetic communities are present in conjunction with large concentrations of migrated hydrocarbons (macroseeps). These generally occur where generation and migration of hydrocarbons from source rocks are ongoing today (at maximum burial) or where significant migration pathways have developed from recent tectonic activity. Passive seeps occur where concentrations of migrated hydrocarbons are usually low (microseeps) with few or no geophysical anomalies. These occur typically in areas where generation and expulsion is relict (no longer at maximum burial) or regional seals prevent significant vertical migration. The type of seepage controls the distribution of migrated hydrocarbons in the near-surface sediments and should dictate the sampling equipment and approach used to detect seeps. Active seeps are usually detected near the water-sediment interface, in the water column or at the sea surface, and at relatively large distances from major leak points. Most conventional sediment and water samplers can capture active seeps. The Gulf of Mexico, Santa Barbara Channel, and parts of the North Sea have active hydrocarbon seeps. Passive seeps can only be detected relatively far below the water-sediment interface and require samples to be collected near leak points. Sampling equipment must penetrate the zone of maximum disturbance or any shallow migration barriers. In areas where surficial sediments are coarse grained or compacted, conventional gravity corers will not work. Other options for subsurface sampling include vibracores, jet cores, and rotary cores. Precise location of samples (site-specific) using seismic profiles to locate leak points is critical to detect passive hydrocarbon seeps. The Beaufort and Bering seas, offshore Alaska, and parts of the North Sea contain passive seeps.