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Abstract Early in 1978, Sandia Labs participated in massive hydraulic fracture mapping experiments with Amoco in the Wattenburg area. On two of these massive hydraulic fractures in the Sussex formation, a downhole, wall clamped, three-axis geophone was tested. On the first experiment, the system was clamped in the open hole section during the breakdown phase. On the second experiment, the system was located in the lubricator during the main fracture and was lowered into place after shut-in. Breakdown pump of the first experiment was conducted in four phases. The formation was first broken down and shut-in for a quiet period and then three 5000 gallon stages of fluid without proppant were pumped with a quiet period after each one. Following the last quiet period, flow back was started and half way through a shut-in was scheduled for the fifth and last quiet period. During even the smallest flow rates, the noise induced into the geophones was extremely large and masked any other seismic activity. During the quiet periods, several seismic events were observed. These apparently are from two sources:motion associated with permanent movements of the fracture face permanent movements of the fracture face and high frequency impulsive sources possibly associated with thermal possibly associated with thermal fracturing. Following the 124,000 gallon fracture on the second experiment, the seismic system was lowered into place and clamped into the casing 50 feet above the open hole section that had been fractured. Seismic signals were recorded for approximately six hours after shut-in when the test was terminated. Both types of signals seen on the early experiment also appear to be present after the fracture treatment. Introduction With the increased use of massive hydraulic fracturing, the knowledge of fracturing dimensions and orientation has increased in importance. The efficient and economic placement of wells for the optimum development of a field will require that fracture orientations be known. Fracture detection and orientation techniques received a considerable effort by El Paso Natural Gas in their Pinedale Field in 1974 and 75. The importance of determining fracture orientations was demonstrated by their research program in fracture mapping and the economic implications were described in reference 2. Seismic detection of fracture signals has been ongoing for several years. In an early attempt to detect fractures at Oak Ridge, surface recording of seismic signals was utilized. The fact that seismic signals are created by hydraulic fracturing and that fracture faces may be mapped by determining the originating point of the signals has been well established. The frequency content of the seismic signals and the attenuation of the earth makes it imperative that seismic recordings be made close to the fracturing if the locations are to be determined. Extensive seismic recordings that were made at the surface during a massive hydraulic fracture in the Wattenburg area by Sandia proved to be incapable of determining fracture orientation. However, seismic signals can be received in the wellbore and these received signals used to map the orientation and plan view of the fracture in the vicinity plan view of the fracture in the vicinity of the wellbore. Following the Wattenburg experiments in 1976, where surface seismic signals were not detected, Sandia initiated their program to develop a borehole seismic program to develop a borehole seismic recording system.
- North America > United States > Texas (0.69)
- North America > United States > Wyoming (0.55)
- North America > United States > Wyoming > Powder River Basin > Sussex Formation (0.99)
- North America > United States > Wyoming > Green River Basin > Pinedale Field (0.99)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Aron, J., Schlumberger-Doll Research Center, Ridgefield, Connecticut Murray, J., Schlumberger Well Services, Houston, Texas Seeman, B., Member SPE-AIME, Etudes et Productions Schlumberger, Clamart, France Productions Schlumberger, Clamart, France Copyright 1978, American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Petroleum Engineers, Inc. This paper was presented at the 53rd Annual Fall Conference and Exhibition of the Society Petroleum Engineers of AIME, held in Houston, Texas, Oct. 1โ3, 1978. The material is subject to correction by the author. Permission to copy is restricted to an abstract of not more than 300 words. Write: 6200 N. Central Expwy, Dallas, Texas 75206. Abstract This paper describes experimental instrumentation and techniques for estimating both compressional and shear interval transit times. The instrument permits the digital recording of propagating acoustic wave-forms as seen at a long spacing by its four receivers. Digital-signal-processing techniques, notably correlation, are used to estimate interval transit times from the recorded waveforms. Examples waveforms and logs, including a cased-hole Sonic log, are displayed. Introduction Borehole logs of acoustic wave-propagation velocity are generally in terms of interval transit time (the reciprocal of the velocity). These logs reflect the effects of a number of formation parameters, such as the elastic constants and matrix density. Compressional and shear interval transit time logs find present or potential applications in porosity determination, synthetic seismograms, determination of formation mechanical properties, fluid identification, and lithology identification. Conventional Sonic logging involves a borehole tool with one or two transmitter(s) and one or two pair(s) of receivers. The transmitter emits an oscillatory burst of acoustic energy, which excites the propagation of various waves (compressional and shear) in the formation, in the borehole fluid, and at the fluid/formation interface (pseudo-Rayleigh and Stoneley waves). Depending on borehole conditions, the different arrivals of these waves will contribute to the signal at a receiver. An illustrative received waveform is shown in Fig. 1. Generally the first energy in the signal is in the formation compressional wave arrival. At some later time in the signal there may be a formation shear wave arrival. Finally, borehole fluid and interface arrivals occur, each arrival traveling at its own specific velocity. In addition parasitic arrivals are produced by bed boundaries and borehole rugosity, and some produced by bed boundaries and borehole rugosity, and some noise originates from the electronics. In classical Sonic logging only the compressional interval transit time (tc) is measured. This value is derived from the difference between the compressional first arrival times (found by threshold detection) at two receivers. This value is reasonably accurate since the compressional arrival is easily detected because it arrives first and because at the spacings generally used it stands out against the background noise preceding it. preceding it. Estimation of the shear interval transit time () could be done in a similar way. However, because the onset of the shear arrival is not always well defined, the use of threshold detection is prone to error. This paper describes an alternative instrumentation and a signal-processing approach, which are applicable to both compressional and shear interval-transit-time measurements.
- Geology > Rock Type (0.50)
- Geology > Geological Subdiscipline > Geomechanics (0.48)
- Geophysics > Borehole Geophysics (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (0.68)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
van Deemter, Henk,* and van der Kallen, Albert W.H.,* *Shell Internationale Petroleum Maatschappij, assigned to Nederlandse Aardolie Petroleum Maatschappij, assigned to Nederlandse Aardolie Maatschappij, (NAM), Assen, The Netherlands Abstract In 1975 a three-dimensional seismic survey was carried-out near Coevorden (Drenthe Province in the eastern part of the Netherlands some 60 kms-5 mi-south of the Groningen gasfield, see fig. 1) covering a rectangular area of 4, 8 ร 3, 25 kms (3 ร 2 mi). This area is situated in a region known for its structural complexity. After 3D-processing including 3D-migration (completed in 1976) it appeared that the 3D-data contained much more information than the conventional 2D-seismic sections and allowed a detailed structural interpretation. As a result the subsurface target of a gas appraisal well could be selected in a structurally more favourable position, i.e. around 1250 m. (4100 ft) southsoutheast of the surface location. Subsequent drilling of this well (completed early 1978) confirmed the correctness of the interpretation. Introduction Appraisal drilling for natural gas on a high block in the Coevorden area (fig. 13) was delayed for some years as even a rather dense network (+ 250 ร 250 m - 820 ร 820 ft) of 2D-seismic data could not provide conclusive evidence for structural closure. In 1975 the Nederlandse Aardolie Maatschappij (NAM) was approached by Shell Internationale Petroleum Maatschappij, The Hague (SIPM) with the question whether NAM would be interested in a 3D pilot project, preferably in an area where it could be of help in a field development plan. NAM accepted SIPM's proposal and selected the rectangular area indicated on fig. 13 for a 3D seismic survey, where the information, besides its value as a pilot study, could help NAM's Production Geological Department in unraveling the structurally complex subsurface. The fieldwork was carried out by a German-based contractor under supervision of both SIPM and NAM. Seismic 3D data processing was done by a major contractor in Dallas (Texas, USA) under supervision of SIPM. The structural interpretation of the processed data was carried by NAM staff. In the following a review will be given of the geological/geophysical problems in the area concerned. The 3D-data will be compared with the original 2D-data to indicate to what extent 3D stacking and migration has contributed to the clarification of the structural picture at the main prospective level, leading to the successful drilling prospective level, leading to the successful drilling of an appraisal well. GEOLOGICAL SETTING IN THE AREA (fig. 2) The primary objective in the area for natural gas-exploration and -development is the Zechstein Z2-carbonate of late Permian age. The directly underlying Z1-sequence of anhydrite, carbonate and Coppershale rests unconformably on a peneplaned surface of the Upper Carboniferous Coalmeasures, the sandy intervals of which form a secondary objective. Natural gas originates from the Coalmeasures, generation and migration having taken place from Upper Cretaceous times to Recent. place from Upper Cretaceous times to Recent. The main seal is formed by the Z2 rock-salt overlying the Z2-anhydrite/carbonate interval. The Z2/Z1 sequence and the Carboniferous formations are dissected by numerous faults, sometimes with considerable throw (up to 500 m - 1640 ft), which predominantly control the traps. Interspersed in the Zechstein salt are slabs of competent rocks (Z3 anhydrites, dolomites and limestones) of largely unknown size and shape. They can be strongly independently tectonized: in some wells duplication and even triplication of the same markerbed has been observed.
- North America > United States > Texas > Dallas County > Dallas (0.24)
- Europe > Netherlands > South Holland > The Hague (0.24)
- Europe > Netherlands > Drenthe > Assen (0.24)
- Phanerozoic > Paleozoic (1.00)
- Phanerozoic > Mesozoic > Cretaceous > Upper Cretaceous (0.44)
- Geology > Structural Geology > Tectonics (0.94)
- Geology > Rock Type > Sedimentary Rock > Carbonate Rock (0.68)
- Geology > Mineral > Sulfate > Anhydrite (0.67)
Abstract The seismic reflection method is well established in the exploration end of the petroleum industry but little used in reservoir analysis by petroleum engineers. As the major structures have been discovered in many areas, seismic profiling has been turned more and more toward smaller structures and toward exploration for stratigraphic traps which require a far greater precision and fineness of detail to locate. This redirection has precision and fineness of detail to locate. This redirection has resulted in improved seismic equipment design, field recording techniques and seismic data processing procedures. This means that the petroleum engineer, for the first time, may be able to utilize this technique to assist in delineation of the fine subsurface stratigraphy within individual reservoirs. The technique used for high resolution reservoir profiling is a greatly scaled-down version of that employed in most exploration operations. Every 5 to 20 meters (16 1/2 to 65 feet), a detector produces a new seismic "pseudo" log trace which will subsequently produces a new seismic "pseudo" log trace which will subsequently be correlated with borehole logs and other seismic log traces. Structural information derivable from the log trace displays includes location of very small faults, sand channels and shale-outs. Shape variations in the log traces can provide the petroleum engineer with valuable reservoir information regarding localized depositional environments, pore fluid characteristics, and even porosity and permeability variations across a given reservoir bed, porosity and permeability variations across a given reservoir bed, once a local reference has been established. Acoustical amplitude analysis of injected, produced or in situ reservoir gases should be a valuable method of monitoring a variety of enhanced oil recovery techniques. Carbon dioxide or other gas injection projects are ideal for seismic pseudo log monitoring. Combustion products from fire floods or injected steam should also be easily seen with high resolution seismic techniques. High frequency surface to surface seismic profiling offers great potential as a reservoir analysis tool. This potential will be developed by the petroleum engineer working with seismic log displays and field well logs rather than exploration geophysicists using smoothed structural displays. Introduction Porosity, fluid saturation, rock compressibility, permeability and capillary pressure are all terms familiar to the permeability and capillary pressure are all terms familiar to the reservoir engineer but seldom used by the geophysicist. On the other hand root mean square velocity, predominant reflection frequency, normal moveout, wavelet amplitude, deconvolution and other terms in the geophysicists vocabulary are almost never involved in reservoir analysis. Until recently, this language problem created no particular difficulty since the geophysicists were almost exclusively involved in exploration activities where the targets were big structures and the geological "details", involving potential reservoir rock type, matrix porosity and permeability as well as pore fluid identification, were considered inconsequential as they routinely fell beyond the resolving power of the seismic reflection method. This has now changed. As the larger structures have been discovered, exploration activities are being redirected to smaller features and especially to stratigraphic traps which require much greater geophysical precision to locate. Demand for increased fineness of detail is resulting in improved geophysical equipment, field recording techniques and computer processing procedures. These improvements allow one for the first time to look at the individual producing formations of immediate interest to the petroleum engineer. petroleum engineer. The change started a few years ago when seismic "Bright Spots" were heralded as a direct hydrocarbon indicator. The "Bright Spot" is caused by the increased seismic reflection amplitude caused by the relatively lower density and velocity of gas filled reservoirs compared to those filled with water. As many operators discovered somewhat later, coal also has low density and velocity and produced bright spots which were easily mistaken for gas. Also depending on the reservoir material, the "Bright Spot" may in fact be a "Dim Spot" or may have no measurable amplitude effect at all.
- Geology > Geological Subdiscipline > Stratigraphy (0.88)
- Geology > Petroleum Play Type > Conventional Play > Stratigraphic Play (0.44)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.36)
Abstract Seismic and petrophysical data sets are processed to acoustic impedance. The petrophysical processing is divided into three phases. The first involves the preparation of a depth-sampled acoustic-impedance log corrected for environmental effects. Re-sampling in time and band limitation of the acoustic-impedance log yields at the end of second-phase processing a synthetic seismic trace that can be used to identify lithological units on a seismic section. Third-phase processing provides the information necessary for interpreting seismic-amplitude values. As an example, the loop associated with a potential reservoir sand is identified and traced along several seismic sections. Amplitude measurements taken from this loop are interpreted in terms of expected fluid content, and a porefill-distribution map of the reservoir is constructed. Introduction Recent improvements in seismic data acquisition and processing have produced a seismic trace which, in favourable cases, closely resembles an acoustic-impedance log (product of velocity and density logs) through the earth. These acoustic-impedance profiles can be interpreted in terms of lithology and porefill. A prerequisite for such detailed analysis is that a data learning set should be available. In the Royal Dutch/Shell Group the necessary information is derived from petrophysical well logs and geological data. In this paper we shall describe the integration of seismic and petrophysical/geological knowledge to detect and map areas of hydrocarbon-bearing sands developed in a marginal marine facies in the depth range 7 000 - 10 000 ft (2 134 - 3 548 m). Emphasis will be given to petrophysical data processing, which we shall divide into three parts. First-phase processing leads to an acoustic-impedance log sampled in depth and characterizing the formation undisturbed by the drilling process. Second-phase processing involves comparing band-limited acoustic impedance logs in the time domain with seismic acoustic-impedance traces around the well location. A positive identification of lithological units on the seismic sections affords the possibility of quantitatively analyzing the seismic data. In order to be able to interpret the analysis results, third-phase processing is necessary. The adopted method gives also the nature of the hydrocarbon-fill, provided that allowance is made for fluctuations in reservoir quality and that there is sufficient acoustic-impedance contrast between oil-filled and gas-filled sands. The minimum acoustic-impedance contrast resolvable is dictated by the noise content and frequency bandwidth of the seismic signal. Geological Background The hydrocarbon reserves in the field under investigation are contained in roll-over structures that are associated with growth faults. The host sediments are marginal marine deposits of Upper Tertiary age consisting of a large number of sedimentary offlap cycles each of which starts with a marine clay and progressively changes upwards into proximal fluviomarine interlaminated silts, sands and clays. First-Phase Petrophysical Processing The digitized well logs with a sampling increment of 0.5 ft (152 mm) were inspected for digitisation and calibration errors, noise spikes, cycle skips, wash-outs, shale-alteration effects and filtrate-invasion effects, and the necessary correction procedures implemented along the lines of the methods described by Dominico and Ausburn.
- Geology > Sedimentary Geology > Depositional Environment (0.75)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Sandstone (0.47)
Abstract Wave tests, performed in an area near Tulsa, OK, using both vertical and in-line horizontal component seismometers, show some interesting events that may be interpreted as backscattered waves from inhomogeneous regions. Normal wave tests (i.e., where seismometers record the signals generated at a fixed source location) and the corresponding transposed wave tests (i.e., where a seismometer occupies the previous source location and the source points o previous source location and the source points o the previous seismometer locations progressively were performed. As previously reported, the transposed wave test seismogram sections show significant improvement in trace-to-trace coherency over the normal wave test sections. However, in this experiment the transposed horizontal component seismogram section shows some events that apparently are not discernible on the corresponding vertical component seismograms. These are believed to be due to backscattering from randomly inhomogeneous zones where considerable conversion of compressional waves to shear waves takes place. This raises the possibility of locating geological features such as possibility of locating geological features such as unconformities, lenses, fracture zones, etc. Another interesting possibility is that scattering and conversion to shear waves may take place close to the seismometers, resulting in their successful recording on a horizontal component seismometer as opposed to a vertical component seismometer. This again raises the hope that areas that have heretofore been labeled NG may be explored using appropriate seismic techniques. The different possibilities need further research and development that would also be beneficial to static corrections in routine seismic surveys. Introduction Seismogram sections basically are geologic cross-sections displaying the variations of elastic properties of the subsurface with depth. These properties of the subsurface with depth. These seismograms are composited from a large number of single seismic traces after appropriate corrections are made for the source-receiver geometry and the near-surface layer travel times. Corrections for the near-surface have been made traditionally with the basic assumption that the elastic waves that are recorded are compressional or P-waves. However, investigations into this problem in a particularly difficult area, the clinker area of Wyoming, show that this is not so. Failure to make appropriate allowances for this effect results in a distorted structural picture of the subsurface. The presence of a very strong shear wave is demonstrated on horizontal component seismograms. These events may be interpreted in three different ways, each with economic value in exploration. The paper deals with illustrations and interpretation of paper deals with illustrations and interpretation of observations using scattering theory. SCATTERING OF ELASTIC WAVES IN RANDOMLY INHOMOGENEOUS MEDIA Lord Rayleigh pointed out that the scattered wave amplitude at distances large compared with the incident wave length is inversely proportional to the distance from the scatterer to the point of observation, directly proportional to the volume of the scatterer, and inversely proportional to the square of the wave length. Theoretical solutions are possible only when very simplifying assumptions are made and almost always the far-field solution is obtained. Knopoff and several others have computed far-field solutions for specific models and have formulated the general problem of seismic-wave scattering. Scattering in problem of seismic-wave scattering. Scattering in a randomly inhomogeneous medium involves considerable conversion of compressional wave energy to shear wave energy. Experimental observations are in agreement with the simplified models theoretically investigated by other workers. For example, Hudson derived formulas comparing scattered S-wave energy with scattered P-wave energy as a function of the P- and S-wave P-wave energy as a function of the P- and S-wave velocities for the simple surface wave scattering model he was investigating.
- North America > United States > Wyoming (0.67)
- North America > United States > Texas (0.47)
- North America > United States > Oklahoma > Tulsa County > Tulsa (0.24)
- Geophysics > Seismic Surveying > Surface Seismic Acquisition (1.00)
- Geophysics > Seismic Surveying > Seismic Processing (1.00)
- Geophysics > Seismic Surveying > Seismic Modeling > Velocity Modeling (0.34)
- North America > United States > Wyoming > Powder River Basin (0.99)
- North America > United States > Montana > Powder River Basin (0.99)
- North America > United States > Wyoming > Wind River Basin > Madison Formation (0.98)
Abstract The determination of the velocity of seismic waves as a function of depth at a well is generally based on the sonic log often complemented by well shooting. Thus, sonic logs in addition to their contribution to the study of the porosity of geological formations contribute to the improvement of surface seismic data and their interpretation. However, events recorded on surface seismograms are reflections while sonic logs and well surveys record arrivals of direct transmitted waves. Thus, identifications of seismic mirrors are inferred on the basis of velocity contrasts and travel times without direct experimental evidence linking the sonic log and the surface seismogram. The roles of multiple reflections and mode conversion remain hypothetical. Reflection coefficients can merely be estimated. The Vertical Seismic Profile (VSP) corresponding to a well is the seismogram which would be obtained when shooting near a well and recording the input from seismic traces regularly spaced inside the well. A VSP provides the missing direct experimental link between surface seismograms on one side and sonic logs and checks shot results on the other side. Actually, for a relatively modest additional effort invested in field operations and processing, a VSP can produce all the information contained in a normal well velocity survey and much more. VSPs may be used for the delineation of reservoirs, the identification and analysis of seismic events and thorough velocity studies where anisotropy is considered. While logs are influenced by a relatively small volume of geological formations around the well, VSPs allow studies where considered dimensions are at least those of the Fresnel Zone. Introduction A sonic log or continuous velocity log of a well indicates the transit time for acoustic waves in microseconds per foot or per meter as a function of depth. It is a very valuable document for porosity determination, moreover it reflects in great detail the stratigraphy of a sedimentary series. The quality of correlations between sonic logs obtained in wells several tens of miles apart is frequently surprisingly good. Actually, it may be said that the ultimate wish of users of seismic sections is to have them transformed into a continuous series of sonic logs. This will most probably remain a wish. Although interesting attempts are being made. Figure 1 is an example of a section where relative isovelocities are contoured. It is the result of a so-called inversion of a seismic reflection section. The well velocity log has been filtered through a band pass filter in order to remove the high and the very low frequencies which cannot be recorded through seismic channels. Thus, what is left is a plot of "relative velocities" as a function of time. Both the thin velocity anomalies and the general increase of velocities with depth are absent There is obviously a strong similarity between the filtered sonic log and the relative velocity curves deduced from the seismic traces. Strictly speaking, these curves should be considered as representing relative acoustic impedances (products of velocities by densities). Actually where density contrasts are strong and both a sonic and a density log are available, an acoustic impedance log is calculated and used. In many cases, density logs are not available and, moreover, the variations of velocities reflect accurately enough the variations of acoustic impedances.
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Near-well and vertical seismic profiles (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management > Open hole/cased hole log analysis (1.00)
Introduction Well 211/29-1 was the most northerly offshore well in the world when it discovered the Brent Field in Aug. 1971. It was drilled in 470 ft of water ca 100 miles east of the Shetland Islands (Fig. 1) by Shell Expro, the operator for the Shell/Esso joint venture in the U.K. sector of the North Sea. Now, 7 years later, not only the Brent Field itself, but an entire complex of projects both on and offshore - perhaps the most difficult offshore activity ever undertaken - is well under way. DISCOVERY WELL RESULTS AND GEOLOGICAL PICTURE Well 211/29-1 found an oil column of 197 ft with an apparent oil-water contact in an 800-ft-thick Middle Jurassic sand body, now known as the Brent sands. Four wireline formation tests (FIT's) were carried out in the well, indicating that the sands had high (up to severed darcies) permeability and contained oil of 39 deg. API with a GOR of 1200 scf/bbl. Saturation pressure was 4200 psig, well below the reservoir pressure of some 6000 psig, so the reservoir appeared quite undersaturated. Appraisal of the discovery was not possible until 1972, as at that time rigs could not operate in the severe winter conditions of the northern North Sea. Initial development, therefore, was planned only on the basis of the limited data from the discovery well, a detailed seismic evaluation, and the regional geological picture. The subsurface picture of the field at the time of completing Well 211/29-1 showed the reservoir to he on a westerly dipping, monoclinal flank with closure to the east provided by a major fault zone. The Middle Jurassic sand and the major fault system were seen to be unconformably overlain by an Upper Jurassic organic-rich shale of Kimmeridgian age. This unconformity, call the X-unconformity, was the horizon that could be mapped regionally by seismic. Postdepositional movement of the major fault blocks Postdepositional movement of the major fault blocks had folded the X-surface, providing the seismic lead for the prospect. Closure to the north and south was conjectural at that time, but major east-west faults cutting the X-unconformity were identified on seismic. Thus, an oil-bearing structure some 16 km long was mapped. Reference to the excellent paper by Bowen will show the stratigraphy and both regional and local geology as interpreted at that time. The field is located in the Viking Graben. This is the northern extension of the over 1000-km-long rift system of the Viking and Central Grabens. The evolution of thus rift system was described fully by Ziegler. Quoting from his summary, "Development of the North Sea rift system started during the Triassic and dominated the paleographic setting of the area during the Jurassic and Cretaceous. The evolution of the North Sea rift is related to the development of the Arctic-North Atlantic rift zone. The latter reached the stage of crustal separation in early Tertiary, at which time the North Sea rift became inactive." It is of interest to note that outcrops on the southeastern coast of Greenland show remarkable similarity in both structure and stratigraphy to features found in the Viking Graben, though they are separated now by some 1500 km. It appears that the two areas were indeed in geographic proximity up until the time of sea-floor spreading, which began in Permian times. Permian times. The North Sea rift system experienced rapid differential subsidence during Triassic and thoughout Jurassic times. Sedimentation occured as a series of regressive-transgressive cycles. During Bajocian-Bathonian times, in particular, the up to 300-m thick Brent sands-were deposited. These now form an outstanding hydrocarbon reservoir. "Minor rifting pulses preceded a regional transgression during the Callovian and Oxfordian that led ultimately, during Kimmeridgian, to the development of deep water troughs in the Viking and Central Graben. Throughout the Northern as well as parts of the Central North Sea, the Kimmeridgian is parts of the Central North Sea, the Kimmeridgian is represented by organic rich shales that constitute the main oil source rock in these areas."
- Europe > United Kingdom > North Sea > Northern North Sea (1.00)
- Europe > Norway > North Sea (1.00)
- Phanerozoic > Mesozoic > Jurassic > Middle Jurassic (1.00)
- Phanerozoic > Mesozoic > Jurassic > Upper Jurassic > Kimmeridgian (0.84)
- Geology > Structural Geology > Tectonics > Extensional Tectonics (1.00)
- Geology > Geological Subdiscipline (1.00)
- Geology > Structural Geology > Fault > Dip-Slip Fault > Normal Fault (0.85)
- Geology > Rock Type > Sedimentary Rock > Clastic Rock > Mudrock > Shale (0.70)
- Europe > United Kingdom > North Sea > Northern North Sea > South Viking Graben > Block 10/1 > NOAKA Project > Frigg Field > Frigg Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/8 > Ninian Field > Brent Group Formation (0.99)
- Europe > United Kingdom > North Sea > Northern North Sea > East Shetland Basin > Block 3/3 > Ninian Field > Brent Group Formation (0.99)
- (23 more...)
- Reservoir Description and Dynamics > Reservoir Characterization > Faults and fracture characterization (0.74)
- Management > Asset and Portfolio Management > Field development optimization and planning (0.68)
- Reservoir Description and Dynamics > Reservoir Characterization > Exploration, development, structural geology (0.68)
- (5 more...)
American Institute of Mining, Metallurgical, and Petroleum Engineers, Inc. Abstract Mapping of massive hydraulic fractures allows for their efficient use to stimulate natural gas production in tight formations. A mapping technique has been used by Sandia Laboratories in conjunction with industry in the Green River Basin at Pinedale, Wyoming and in the Wattenburg field near Denver, Colorado. Comparison of field data to model calculations shows that the electrical potential gradients produced by the direct electrical excitation of the produced by the direct electrical excitation of the fracture well and fracture fluid can be used to map and characterize massive hydraulic fractures. The direction and any asymmetry of the fracture can be determined. Introduction In April 1973, a special Natural Gas Technology Task Force issued a preliminary report on three major gas deposits in the Rocky Mountain region which cannot be exploited with current extraction techniques. The regions considered were the Green River Basin in Wyoming, the Piceance Basin in Colorado, and the Uinta Basin Piceance Basin in Colorado, and the Uinta Basin in Utah. The low permeability of the gas bearing sands in these basins dictates that extremely large fractures are required to provide adequate productivity. The report indicates that the gas deposits could be stimulated by massive hydraulic fracturing (MHF). Massive hydraulic fracturing stimulation consists of multi-stage sand and fluid injections that would potentially create long fractures (appx. 5000 ft.) over a large gross pay interval. To assess the efficiency of the MHF process, characterization information is needed on the azimuthal direction, length, and height of the permeable portion of the hydraulic fractures. In addition, for production application of MHF, similar information will be needed to affect optimum well placement to achieve overall efficient drainage. Sandia Laboratories is currently developing geophysical diagnostic techniques to characterize and map massive hydraulic fractures. These techniques include the use of passive seismic signals created by the fracturing and surface electrical potentials created by injecting current into the casing of the fracture well. In this paper, the modeling and field results of recent tests for the surface potential technique will be given. The electrical MHF mapping technique consists of measuring potential gradients at the surface of the earth. The potential gradients are a result of using the fracture well casing along with the associated fracture filled with a conducting fracture fluid as one current electrode and a distant well casing as the other current electrode.
- North America > United States > Wyoming (1.00)
- North America > United States > Utah (1.00)
- North America > United States > Colorado > Denver County > Denver (0.24)
- North America > United States > Wyoming > Uinta Basin (0.99)
- North America > United States > Wyoming > Green River Basin (0.99)
- North America > United States > Utah > Uinta Basin (0.99)
- (3 more...)
- Well Completion > Hydraulic Fracturing (1.00)
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
Abstract Electrical resistivity and passive acoustic techniques have been used to remotely monitor the location of the reaction zone in an in situ coal gasification experiment conducted near Hanna, Wyoming. Thermal measurements were made to provide diagnostic information, to aid in provide diagnostic information, to aid in understanding the process, and to evaluate the effectiveness of the remote techniques. From a comparison of field resistivity data and model calculations the path of the reaction zone was determined. Source locations in the overburden for acoustical events during gasified area. The feasibility of these remote techniques to monitor in situ coal gasification has been demonstrated. Introduction The Laramie Energy Research Center (LERC) conducted an underground coal gasification (UCG) experiment at a site near Hanna, Wyoming from March 1973 to March 1974. This experiment, Hanna I, demonstrated that western coals were suited to underground gasification and that it was possible with only air injection to produce 125 Btu/scf gas for an extended period of time. Sandia Laboratories participated during this experiment and demonstrated that resistivity, acoustic, and temperature measurements could detect effects associated with the process. Phase 1 of a Hanna II experiment was conducted Phase 1 of a Hanna II experiment was conducted May through August, 1975. This phase was designed to determine in situ permeability, to examine pneumatic and combustion linking of wells and to conduct a brief gasification test. Phases 2 and 3, the linkage and gasification Phases 2 and 3, the linkage and gasification between a pair of wells and evaluation of a linedrive concept for areal recovery were conducted from April through July, 1976. These experiments have been based on the linked vertical well concept. In this concept communication between the injection and production (recovery) wells through the coal seam production (recovery) wells through the coal seam is accomplished by thermal linking. In this method the coal is ignited at the production well, while air is supplied at the injection well. The combusion front follows natural fissures toward the source of oxygen and develops a localized permeable path of hot, carbonized coal. When the permeable path of hot, carbonized coal. When the combusion front reaches the injection well there is an abrupt drop in injection pressure to less 50 psi with a significant increase in the flow rate. psi with a significant increase in the flow rate. Once linkage is established combusion mode in which the combusion front moves in the direction of air flow along the permeable link. LERC is now conducting a second UCG experiment which has been designated as Hanna II. Sandia Laboratories' participation in the Hanna II series of experiments is to develop and evaluate instrumentation techniques that will provide subsurface diagnostic information as an aid toward understanding the retorting process and to study commercially practical techniques to observe the subsurface burn with remote monitoring.
- Reservoir Description and Dynamics > Reservoir Characterization > Seismic processing and interpretation (1.00)
- Reservoir Description and Dynamics > Improved and Enhanced Recovery (1.00)
- Reservoir Description and Dynamics > Formation Evaluation & Management (1.00)
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