Low Gas Saturation Research Articles

Experimental investigation and evaluation of three-phase relative permeability models

Petroleum production often involves simultaneous flow of three immiscible fluids through underground porous rock formation. In this work, we measure two- and three-phase relative permeabilities with which we examine the performance of various 3-phase relative permeability models. The rock–fluid systems used in these measurements are comprised of sandstone samples, oil (n-decane), water (Nacl, 6000ppm) and gas (nitrogen). The measurements were carried out at 23±1°C and 5.44MPa. Two- and three-phase relative permeability measurements were obtained using the steady-state technique. The three-phase experiments were conducted such that the flow rates of brine and gas were increased gradually and oil rate was decreased to simulate the reservoir behavior during primary oil production. Several different flow rate ratios were selected so as to cover the saturation ternary diagram as completely as possible. The three-phase experimental results were compared with the prediction by different models which obtained by an in-house developed three-phase software. The results showed that in the primary imbibition case, the Blunt and Baker methods are more reliable than the other methods at low gas saturations.

Identification of the Quaternary low gas-saturation reservoirs in the Sanhu area of the Qaidam Basin, China

Low gas-saturation reservoirs are gas bearing intervals whose gas saturation is less than 47%. They are common in the Quaternary of the Sanhu area in the Qaidam Basin. Due to the complex genesis mechanisms and special geological characteristics, the logging curves of low gas-saturation reservoirs are characterized by ambiguity and diversity, namely without significant log response characteristics. Therefore, it is particularly difficult to identify the low gas-saturation reservoirs in the study area. In addition, the traditional methods such as using the relations among lithology, electrical property, physical property and gas bearing property, as well as their threshold values, can not effectively identify low gassaturation reservoirs. To solve this problem, we adopt the decision tree, support vector machine and rough set methods to establish a predictive model of low gas-saturation reservoirs, which is capable of classifying a mass of multi-dimensional and fuzzy data. According to the transparency of learning processes and the understandability of learning results, the predictive model was also revised by absorbing the actual reservoir characteristics. Practical applications indicate that the predictive model is effective in identifying low gas-saturation reservoirs in the study area.

The influence of gas saturation and pore pressure on the characteristics of the Frenkel-Biot P waves in partially saturated porous media

For the case of a partially saturated porous medium, analysis of the conditions is carried out under which the properties of the Frenkel-Biot P waves are similar. The condition of dynamic compatibility (with fulfillment of which a wave of the first kind is propagated without attenuation) is generalized to the case of partially saturated porous media. It is found that the wave connected with the matrix deformation possesses a high attenuation coefficient in a porous medium saturated with a weakly-compressible liquid, but it is a weakly decaying wave in a gas-saturated porous medium. Asymptotic formulas for phase wave velocities are obtained within a low-frequency and high-frequency limit for the general case of a partially saturated porous medium. It is shown that in the domain of low gas saturation, the attenuation coefficient of a wave of the first kind (i.e., a wave connected with the compressibility of phases) depends on the state of the gas in porous space. The following three cases are considered: (1) the microbubbles occluded in the saturating liquid; (2) the microbubbles adsorbed on the walls of pores; and (3) the macrobubbles that completely occupy one or several pores. This characteristic can be used as the diagnostic parameter.

A Model of Buoyancy-Driven Two-Phase Countercurrent Fluid Flow

We seek simple analytical solutions in a model of gas flow driven by a combination of buoyancy, viscous, and capillary forces. Traveling-wave solutions describe propagation of the top and bottom of the gas plume. The top of the plume has low gas saturation, but propagates much faster than the bottom. The theoretical maximum of the velocity of propagation of the top of the plume provides a simple conservative estimate of the time until plume evolution will dramatically slow down. A sequence of rarefaction and traveling-wave solutions characterizes the transition zones between the top and bottom stable regions. The analytical results are applied to studying carbon dioxide flow caused by leaks from deep geological formations used for CO2 storage. The results are also applicable for modeling flow of natural gas leaking from seasonal gas storage, or for modeling of secondary hydrocarbon migration.

Diagenetic history of tight sandstones and gas entrapment in the Yulin Gas Field in the central area of the Ordos Basin, China

The Ordos Basin is a large cratonic basin with an area of 250,000 km 2 in central China. Upper Paleozoic coals and shales serve as gas source rocks with peak generation and migration at the end of the early Cretaceous. Recent exploration has verified the huge gas potential in the “basin-centered gas accumulation system” (BCGAS). However, the mechanism for the gas accumulation is controversial. With an integrated approach of thin-section petrography, ultra-violet fluorescence microscopy, fluid inclusion microthermometry, Raman microspectrometry, scanning electron microscopy, and X-ray diffractometry, we identified diagenetic trapping and evaluated the diagenetic history of sandstone reservoirs in the Yulin Gas Field in the central area, where structural, stratigraphic and/or sedimentary lithologic traps have not been found. It was revealed that three phases of diagenesis and hydrocarbon charging occurred, respectively, in the late Triassic, late Jurassic and at the end of the early Cretaceous. In the first two phases, acidic water entered the reservoir and caused dissolution and cementation, resulting in porosity increase. However, further subsidence and diagenesis, including compaction and cementation, markedly reduced the pore space. At the end of the early Cretaceous, the bulk of the gas migrated into the tight reservoirs, and the BCGAS trap was formed. In the updip portion of this system, cementation continued to occur due to low gas saturation and has provided effective seals to retain gas for a longer period of time than water block in the BCGAS. The mechanism for the gas entrapment was changed from water block by capillary pressure in the BCGAS to diagenetic sealing. The diagenetic seals in the updip portion of the sand body were formed after gas charging, which indicates that there is a large hydrocarbon exploration potential at the basin-centered area.

From deep basin gas to diagenetic trap—An example from the Yulin Gas Field in the Ordos Basin

In the updip portion of the Yulin Gas Field in the Ordos Basin, there are no any structural, stratigraphic and sedimentary lithologic seals. Using thin-section petrography, ultraviolet fluorescence microscopy, micro-thermometry and Raman microspectrometry, this paper finds out the diagenetic trap and studies the diagenetic history of this field. It was revealed that three phases of diagenesis and hydrocarbon charging happened in late Triassic, late Jurassic and the end of early Cretaceous respectively. In the first two phases, acid geofluid entered the reservoir and caused dissolution and cementation. Although the porosities had been increased, further compaction accompanying re-subsidence resulted in tight sandstone and conglomerates. Till the end of the early Cretaceous, bulk of gas migrated into the tight reservoir. Cementation, however, kept on in the updip portion of this field due to low gas saturation and formed the diagenetic trap. The mechanism for gas accumulation was changed from deep basin gas to diagenetic trap, which offers a sealing condition that can retain gas for much longer time.

Sensitivity analysis of seismic reflectivity to partial gas saturation

We analyze the sensitivity of seismic reflectivity to contrasts in density, seismic propagation velocities, Poisson’s ratio, and gas saturation using the complete Zoeppritz equations. Sensitivities of reflection coefficients to each bulk elastic parameter are computed as the partial derivatives of the seismic reflectivities, relative to each parameter. The sensitivity of reflectivity to gas saturation is then calculated as the full derivative of the reflectivities with respect to gas saturation, assuming both a homogeneous and a patchy distribution of gas in the pore fluids. We compute sensitivities for a sealing shale/gas-sand interface and a gas-sand/wet-sand (gas-water contact, GWC) interface. For the SH-SH reflectivity, the effect of density contrast is strongest in the 30°–50° range of incidence angles for the fluid-fluid interface and at nearer offsets for the shale/gas-sand interface. P-SV reflectivity forthe fluid-fluid interfaces is more sensitive to density contrast in the range of angles of incidence from 30° to 60°. The overall response of P-SV reflectivity to gas saturation throughout all offsets is dominated by the Poisson’s ratio of the gas sand. In the case of P-P reflectivity, the sensitivity to gas saturation increases with increasing incidence angles. The sensitivity of P-SV reflectivity to gas saturation tends to be greatest in the 20°–40° range of incidence angles. For SH-SH reflectivity, the sensitivity to gas saturation for most offsets is controlled mainly by the density contrast, and the sensitivity to density decreases with increasing offset. There is still not a generally accepted seismic reflection method to discriminate commercial gas concentrations from low gas saturation. From the sensitivity analysis, we conclude that the use of P-SV or SH-SH amplitude variation with offset (AVO), integrated with the P-P AVO, will be an essential element in understanding this problem fully.

Seismic attenuation from VSP data in methane hydrate-bearing sediments

Recent seismic surveys have shown that the presence of methane hydrate (MH) in sediments has significant influence on seismic attenuation. I have used vertical seismic profile (VSP) data from a Nankai Trough exploratory well, offshore Tokai in central Japan, to estimate compressional attenuation in MH-bearing sediments at seismic frequencies of 30–110 Hz. The use of two different measurement methods (spectral ratio and centroid frequency shift methods) provides an opportunity to validate the attenuation measurements. The sensitivity of attenuation analyses to different depth intervals, borehole irregularities, and different frequency ranges was also examined to validate the stability of attenuation estimation. I found no significant compressional attenuation in MH-bearing sediments at seismic frequencies. Macroscopically, the peaks of highest attenuation in the seismic frequency range correspond to low-saturation gas zones. In contrast, high compressional attenuation zones in the sonic frequency range (10–20 kHz) are associated with the presence of methane hydrates at the same well locations. Thus, this study demonstrated the frequency-dependence of attenuation in MH-bearing sediments; MH-bearing sediments cause attenuation in the sonic frequency range rather than the seismic frequency range. As a possible reason why seismic frequencies in the 30–110 Hz range were not affected in MH-bearing sediments, I point out the effect of thin layering of MH-bearing zones.

Integration of electromagnetic and seismic data to assess residual gas risk in the toe-thrust belt of deepwater Niger Delta

During the last couple of years, drilling activities in the deepwater thrust belt play of Nigeria (Figure 1) have shown mixed results with some wells finding pay but others coming across low-saturation gas and/or brine sands. In this frontier exploration context, Shell Nigeria E&P Co. (SNEPCo) has been particularly successful in a number of toe-thrust prospects where the key risk is trap integrity, related to both earlier thrust faults and later extensional faults.

Gas saturation prediction and effect of low frequencies on acoustic impedance images at Foinaven Field

ABSTRACTLow frequencies are necessary in seismic data for proper acoustic impedance imaging and for petrophysical interpretation. Without lower frequencies, images can be distorted leading to incorrect reservoir interpretation and petrophysical predictions. As part of the Foinaven Active Reservoir Management (FARM) project, a Towed Streamer survey and an Ocean Bottom Hydrophone (OBH) survey were shot in both 1995 and 1998. The OBH surveys contain lower frequencies than the streamer surveys, providing a unique opportunity to study the effects that low frequencies have on both the acoustic impedance image along with petrophysical time‐lapse predictions. Artefacts that could easily have been interpreted as high‐resolution features in the streamer data impedance volumes can be distinguished by comparison with the impedance volumes created from the OBH surveys containing lower frequencies.In order to obtain results from the impedance volumes, impedance must be related to saturation. The mixing of exsolved gas, oil and water phases involves using the Reuss (uniform) or Voigt (patchy approximation) mixing laws. The Voigt average is easily misused by assuming that the end‐points correspond to 0% and 100% gas saturation. This implies that the patches are either 0% gas saturation or 100% gas saturation, which is never the case. Here, the distribution of gas as it comes out of solution is assumed to be uniform until the gas saturation reaches a sufficiently high value (critical gas saturation) to allow gas to flow. Therefore, at low gas saturations the distribution is uniform, but at saturations above critical, it is patchy, with patches that range from critical gas saturation to the highest gas saturation possible (1 minus residual oil and irreducible water saturation).

On the dynamics of capillary gas trapping: implications for the charging and leakage of gas reservoirs

Capillary leakage of gas from buried structures can be quantified using Darcy migration concepts together with formulations for cap-rock permeability, relative permeability and entry pressures at low gas saturations. Capillary trapping has a static component defined by the entry pressure of the cap rock and a dynamic component defined by Darcy migration velocities and rates of migration into the trap. The importance of the dynamic trapping component increases with burial due to a corresponding reduction in cap-rock permeability. The low gas migration velocities through buried cap rocks make it unlikely that gas escape from these traps will be focused above their tops. Barriers within the cap-rock sequence may increase the gas saturation and increase the lateral width of the leakage zone. This may result in complex leakage routes into shallower structures. Source rocks that supply gas to deeply buried traps will start to become exhausted as the temperatures increase. This reduces the rate of gas supply into the traps. Dynamic traps which have trapped gas columns that exceed the capacity of the cap-rock entry pressures can then no longer support the same column heights, and they are reduced in size. The reduction in column heights may continue below the capacity defined by cap-rock entry pressures because of hysteresis effects. The reduction in seal capacity for deeply buried traps can be estimated if the gas fill history of the trap is known. Traps with a low vertical relief can be shielded from the dynamic seal destruction mechanism by the spill process. During periods of reduced or halted gas generation from the source rocks, dynamic traps will continue to leak for million of years. This delayed leakage may be an important source for the filling of shallower traps with gas long after the source rocks have been buried too deeply for generation to take place.

Interpreter's Corner—Seismic amplitudes from low gas saturation sands

In Tertiary age sediments, P-wave seismic amplitudes are generally regarded as the most robust direct hydrocarbon indicators. Exploration prospects based on a sound geologic model and supported by seismic amplitude anomalies are highly prospective and are usually assigned a high probability of success. However, a fraction of such prospects, perhaps 10–30%, result in dry holes. Postdrill appraisal can usually assign these results to one or more of the following factors: When a dry hole cannot be explained by any of these causes, the seismic amplitude anomaly is often ascribed to low gas saturation in the reservoir. Seismic amplitudes are strong indicators of the presence of gas in a reservoir, but poor indicators of gas saturation. As a result, a reservoir with low gas saturation will have a seismic amplitude response comparable to that of a reservoir with high, commercial level saturation. The problem with this explanation lies in the difficulty in measuring low gas saturation in-situ; any independent measurements to confirm the presence of low gas saturation in the reservoir (implied by seismic amplitude analysis) are rare. This raises the question of whether such low gas saturation sands occur in nature with the appropriate rock properties to yield an anomalous seismic amplitude response. In a study of amplitude-supported prospects in deepwater Gulf of Mexico, Gross and Oliver (AAPG Bulletin , 1998) reported that 67% of these prospects were successful, encountering a net hydrocarbon sand interval of 15 ft or greater. However, 18% failed due to low gas saturation, which they were able to identify based on wireline logs. This paper presents …

An NMR study of single- and two-phase flow in fault gouge filled fractures

The characteristics of single- and multiphase flow through fractured rock are of considerable interest in petroleum and natural gas exploitation as well as in the risk assessment of underground repositories. Flow processes of water and gas were studied in a granite core containing a fault gouge filled fracture zone. The pore structure of the sample was scanned by X-ray computed tomography (CT). A reversible change of fracture aperture due to shrinking and swelling of fault gouge was observed when drying, saturating and again drying the core. There is evidence that the fractures at the contact between matrix and fault gouge contribute most to permeability. Changes in the size distribution of water filled pores were monitored by low magnetic field nuclear magnetic resonance (NMR) during miscible flooding with deuterated water and immiscible flooding with nitrogen gas. Gas breakthrough occurred quickly at extremely low gas saturation indicating preferential pathways. Water saturation decreased gradually with the increase of injection pressure. In comparison, the process of miscible flooding showed a much more homogeneous behavior. Deuterated water breakthrough occurred slowly and at higher deuterated water saturation. In miscible flooding, the large and small range of the pore size distribution decreased simultaneously indicating that deuterated water invaded both types of pores at the same time. In the immiscible flooding process, the large pores were preferentially invaded by gas. At low water saturation, water only fills the very small pores, which do not contribute to gas flow.

Useful approximations for converted‐wave AVO

Converted‐wave amplitude versus offset (AVO) behavior may be fit with a cubic relationship between reflection coefficient and ray parameter. Attributes extracted using this form can be directly related to elastic parameters with low‐contrast or high‐contrast approximations to the Zoeppritz equations. The high‐contrast approximation has the advantage of greater accuracy; the low‐contrast approximation is analytically simpler. The two coefficients of the low‐contrast approximation are a function of the average ratio of compressional‐to‐shear‐wave velocity (α/β) and the fractional changes in S‐wave velocity and density (Δβ/β and Δρ/ρ). Because of its simplicity, the low‐contrast approximation is subject to errors, particularly for large positive contrasts in P‐wave velocity associated with negative contrasts in S‐wave velocity. However, for incidence angles up to 40° and models confined to |Δβ/β| < 0.25, the errors in both coefficients are relatively small. Converted‐wave AVO crossplotting of the coefficients of the low‐contrast approximation is a useful interpretation technique. The background trend in this case has a negative slope and an intercept proportional to the α/β ratio and the fractional change in S‐wave velocity. For constant α/β ratio, an attribute trace formed by the weighted sum of the coefficients of the low‐contrast approximation provides useful estimates of the fractional change in S‐wave velocity and density. Using synthetic examples, we investigate the sensitivity of these parameters to random noise. Integrated P‐wave and converted‐wave analysis may improve estimation of rock properties by combining extracted attributes to yield fractional contrasts in P‐wave and S‐wave velocities and density. Together, these parameters may provide improved direct hydrocarbon indication and can potentially be used to identify anomalies caused by low gas saturations.

Distinguishing fizz gas from commercial gas reservoirs using multicomponent seismic data

Partial gas discrimination is a challenging problem because low and high gas saturation can result in very similar seismic AVO, bright spot, and velocity sag anomalies. This is typically explained using Gassmann's theory: i.e., (1) small amounts of gas in the pore space cause large decreases in rock incompressibility while further increasing gas content does not reduce rock incompressibility significantly, and (2) the shear modulus is not affected by nonviscous fluids in the rock pore space. In addition, rock bulk density varies gradually with water saturation, as predicted using the volume-average equation. Consequently, low-gas saturation reservoirs and high-gas saturation reservoirs can have similar VP and VP/VS values (or, equivalently, Poisson's ratios). Therefore, in many cases, high and low gas saturations cannot be distinguished using existing hydrocarbon indicators and techniques. These indicators include those based on VP variations, such as velocity sags, and those based on Poisson's ratio vari...

ABSTRACT: Distinguishing Water Saturation Changes from Porosity or Clay Content Changes Using Multicomponent Seismic Data

Abstract It is difficult to predict whether gas saturation is low or high in reservoir pore spaces prior to drilling. When reservoirs include lateral porosity or clay content changes, this task is even more difficult. However, the problem is easier to address with high-quality multicomponent seismic data. This paper proposes to use Rps/Rpp as a partial gas indicator (PGI), where Rps and Rpp are defined as the change in the P-SV and P-P reflection coefficients, respectively. The target portion of the reservoir is compared to an inferred background portion of the reservoir, which is assumed to be 100% water saturated. The Rps/Rpp ratio behaves quite differently for high and low gas saturations, as shown by theoretical reflection coefficient computation for a range of examples using the Zoeppritz and Gassmann's equations. The responses of Rps/Rpp to porosity and clay content changes are computed using empirical relationships among velocities, porosity and clay content (Wang and Nur, 1992; Han et. al., 1986; Eberhart-Phillips et. al., 1989; Castagna et al., 1985). The ratio is insensitive to the magnitude of porosity or clay content changes, and this behavior is very different from the variations in the ratio associated with changes in gas saturation. Theoretical reflection coefficient computation, modeling and synthetic seismograms show that Rps/Rpp is an effective direct hydrocarbon indicator and PGI for all three classes of gas reservoirs (Rutherford and Willams, 1989) at both shale/sand and sand/shale interfaces. The three classes of reservoirs are classified based on their acoustic impedance contrasts with their overlaying shales. The Rps/Rpp ratio can distinguish water saturation changes from porosity or clay content changes and separate regions of high gas saturation from low saturation areas.

Simultaneous Production of Gas Cap and Oil Column With Water Injection at the Gas/Oil Contact

Summary The conventional way to produce an oil reservoir that has a gas cap is to produce only from the oil column while keeping the gas cap in place so that it can expand to provide pressure support. Depending upon the geometry, reservoir dip angle, and oil production rates, gas can either cone down to the oil producers or breakthrough as a front, leading to substantial increases in the gas-oil ratios of the oil producers. This paper presents a unique production methodology of simultaneously producing the gas cap and oil column while injecting water at the gas-oil contact to create a water barrier to separate the gas cap and oil column. This methodology has application in reservoirs with a low-dip angle, large gas cap, and a low residual gas saturation to water. It is demonstrated that the net present value of the project is improved if there is an immediate market for gas. Geostatistical reservoir models are used to demonstrate that the gas cap recovery is minimally impacted by heterogeneities.

AVO as an Exploration Tool in the Penola Trough, Otway Basin

In 1988, Katnook-1 discovered gas in the basal Eumeralla Formation in the Penola Trough. All subsequent commercial discoveries have been within the underlying Crayfish Group. Amplitude-versus-offset (AVO) analysis performed on single gather records correctly predicted the subsequent discovery of gas within the Crayfish Group in the Katnook-2 and Ladbroke Grove-1 wells. Seismic recorded since 1990 has generally better quality data which are more suitable for AVO analysis. Two lines were recorded in 1993 over the Katnook Field, tied to the three Katnook wells. Only a small AVO effect was predicted at some locations from modelling using the well data, which was probably due to the poor quality well logs. The seismic AVO analysis, however, using all gather records, produced clear anomalies at both reservoir levels which approximately matched the predicted extent of the gas in the field from structural mapping. The subsequent Katnook-4 appraisal well confirmed the presence of gas at these levels, but unfortunately was not commercial. AVO and inversion were also run over the Haselgrove Gas Field prior to its discovery in 1994. AVO anomalies are seen at both Katnook reservoir levels, but the strong basal Eumeralla Formation anomaly is interpreted to be due to a clean, water saturated sand rather than gas. The anomalies at the top Pretty Hill Sandstone level are more consistent with structure although they extend below mapped closure. Subsequent reprocessing using pre-stack migration prior to AVO analysis produced anomalies which closely match the actual gas column height, and are within the zone of strong seismic amplitudes at this level. AVO anomalies in the area appear to be caused by both clean, water filled sands and the presence of hydrocarbons. Seismic inversion can help the prediction of sand quality variations, and the mapped extent of structural closure can be used to identify those AVO anomalies more likely to be related to hydrocarbons. Pre-stack time migration prior to AVO processing is essential in most cases. Unfortunately, AVO anomalies also occur in reservoirs with low gas saturations or low reservoir permeability. Despite these drawbacks AVO with inversion has proven to be a valuable exploration tool in the Penola Trough. No gas discoveries have yet been made which are not associated with an AVO anomaly.

Multidiscipline Studies of the Depletion Behavior of the F23 Gas Field, Offshore Sarawak, East Malaysia: ABSTRACT

The F23 gas field is located 178 km north-northwest of Bintulu in the central Luconia province, offshore Sarawak. The accumulation consists of a late Miocene layered platform-type carbonate buildup 22 km[sup 2] and a maximum gas thickness of over 1000 ft. Eleven development wells and one observation well were completed in 1983, with initial gas delivery to Malaysia LNG in October 1983. Annual TDT surveys are conducted in the observation well to monitor the movement of the GWC in the central area of the field. As of April 1992, a cumulative rise of 25 ft was observed. This contrasts with material balance calculations predicted rise of some 60 ft based on Sgr of 50% inferred from core measurements. Among the potential explanations were irregular bottom-water encroachment, preferential flank water advance, or larger GIIP. As all had potentially important consequences to depletion strategy and ultimate reserves, multidiscipline studies were initiated. Time-lapse seismic data were used to better determine the existing fluid levels across the field and reservoir simulation studies were used to match observation well data and predict future reservoir behavior. Concurrent reservoir and simulation studies suggested that the material balance and observation well data could be reconciled by (1) amore » reduced aquifer, and/or increased GIIP, and/or a lower residual gas saturation, or (2) preferential flank water influx due to internal low-permeability layers. As (1) would not lead to early water breakthrough, the simulation effort was aimed to investigate (2), the possibility and implications of early edge water breakthrough via the flank zone.« less

Seismic reflection amplitude versus angle variations over a thermally enhanced oil recovery site

In recent years it has become increasingly important to develop a capability for monitoring enhanced oil recovery (EOR) processes as they are occurring within any reservoir. An amplitude‐versus‐angle (AVA) analysis over a steam injection location showed encouraging results and established that seismic reflection methods, when well designed and carefully processed, can be used to map the invaded steam zones in steam stimulation EOR operations. The results are imaged on a new type of display called ARPA (amplitude‐ratio for partial angle), which illustrates reflection zones with low or high Poisson’s ratio or equivalently high or low gas saturation with a CMP stack section plotted as the background. A seismic experiment consisting of three reflection lines was carried out by Esso Resources in February, 1984 over a steam injection site near Cold Lake, Alberta. Analysis of the field data showed that large variations in reflected scattered energy were a function of angle of incidence in areas affected by the steam zone.