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Light hydrocarbons produced from unconventional tight shale reservoirs with matrix permeability in nano-Darcy range accounts for more than half of the petroleum production in the United States in the past several years. This has been enabled mainly by the drilling of long horizontal wells coupled with extensive hydraulic fracturing. A typical fracturing job for a horizontal well requires two to five million gallons of water which imposes significant challenges in many areas of the world that lack water resources. In addition, treatment and disposal of produced fracturing fluids can be expensive and may negatively impact the environment. Here we show a ‘water-free’ stimulation method to produce light hydrocarbons from the extremely tight reservoirs using electromagnetic (EM) waves to heat the formation and elevate pore-water pressure. We demonstrated in the laboratory that microwave heating pulverized shales and other tight rocks without confinement and generated extensive fractures within shales with 15 MPa isotropic confinement pressures. Our calculation indicates that for typical shale reservoirs pore-water pressure can increase to 90 MPa or higher that is sufficient to stimulate the formation for production with a less than 100 °C temperature increase of the reservoir. Using a simplified coupled model of EM heating and thermal diffusion, we estimated that with practically reasonable amount of power input the EM heating can stimulate a sufficiently large volume of tight reservoirs to produce light hydrocarbons.

The pressure pulse-decay test has been one of the most widely used techniques to measure permeability for low-permeability rocks including shale, largely because relatively simple analytical solutions to fluid flow in a rock sample (characterized as a single continuum) exist for analyzing late-time test data. This work develops a new analytical solution for analyzing late-time pulse-decay test data for dual-continuum rock samples, motivated by the possibility that shale matrix (not including fractures) may exhibit dual- or multiple-continuum gas-flow behavior owing to its wide spread pore size distributions and property differences between organic and inorganic components of the shale matrix. This issue has important implications for characterizing and modeling gas flow in shale, because a dual-continuum medium involves more flow parameters and requires more complex modeling approaches than a single-continuum medium. Our new analytical solution shows that the relationship between gas pressure measurements from a pulse-decay test and permeability remains the same for both single- and dual-continuum systems, suggesting that shale-matrix permeability data in the literature, previously obtained from pulse-decay tests, are valid although the corresponding shale samples ought to be treated as dual-continuum instead of a single continuum system. In addition, our analytical solution relates mass transfer (between the two continua) to pressure change during late-time of a test. This relationship, with a clear and intuitive physical interpretation rooted in the mass balance principle, provides a simple and practical analysis technique to identify dual-continuum behavior from pulse-decay test data and to estimate mass transfer coefficient between the two continua if the dual-continuum behavior exists. The usefulness of the analytical solution is demonstrated by satisfactory matches with several pulse-decay test data sets. The data analysis results also indicate that not all shale samples exhibit dual-continuum gas-flow behavior regardless of their make-up and complex pore structures.

SummaryTensile strength is a critical parameter for hydraulic fracturing, predicting fracture initiation and propagation in reservoirs, especially in shale reservoirs with complex natural fractures and fissures. The tensile strength of conventional rocks, such as sandstone and limestone, has been well-studied and -documented. There are many studies of the tensile strength of laminated shale, which focus on scale effects, loading direction, and temperature effects; however, the studies on effects of mineralogy and the water content on tensile strength of organic-rich shales are very limited.The objectives of this paper are to (1) critically review the key parameters that affect the tensile strength of shale and 2) experimentally examine the effects of water content, mineralogy, and lamination on tensile strength. To do so, a rigorous workflow is followed: 1) Each 1-in.-long shale sample is cut into two subsamples, A and B, of similar length; (2) X-ray computed-tomography (CT) scan is performed to diagnose pre-existing cracks and defects inside the core plugs; (3) nuclear magnetic resonance (NMR) is then used to measure the air dry samples’ water content; (4) Sample A is placed on a load frame to measure the tensile strength; (5) Sample B is vacuumed and then saturated; (6) NMR is used to measure the water content after saturation; (7) tensile strength of the saturated Sample B is measured; and (8) after the sample fails, the pieces are used for X-ray diffraction (XRD), scanning electron microscopy (SEM), and pyrolysis to estimate the mineralogy and total organic content (TOC).A total of 70 Mancos and 48 Eagle Ford shale samples have been tested. The experimental results show that (1) bedding plane/lamination has a significant effect on Eagle Ford tensile strength, but no pronounced impact is observed for the Mancos shale; (2) the imbibed water significantly reduces the tensile strength by 4.4 to 51.7% as water content increases from 4.45 to 11.7%; (3) pre-existing detectable microfractures can significantly reduce the tensile strength by up to 66%; (4) Eagle Ford exhibits typical brittle hard-rock failure configuration, with primary fractures and secondary fractures being observed, whereas for the Mancos shale, only primary fractures are observed; (5) acoustic velocity-test results confirm that Eagle Ford is mechanically transversely isotropic, and Mancos is likely mechanically isotropic.

Summary Acoustic-velocity measurements are an important nondestructive way to investigate dynamic rock-mechanical properties. Water content and bedding-plane-induced anisotropy are reported to significantly affect the acoustic velocities of siliciclastic sandstones and laminated carbonates. This relationship in organic-rich shales, however, is not well-understood and has yet to be investigated. The mechanical properties of organic-rich shales are affected by changes in water content, laminations, total organic content (TOC), and microstructures. In particular, kerogen density that accompanies changes in the composition of the TOC during maturity can significantly influence the acoustic responses within source rocks. To understand how these variables influence acoustic responses in organic shales, two sets of cores from the Eagle Ford shale were investigated: one set cut parallel to bedding and the other perpendicular to bedding. Textures of the samples from each set were characterized by use of computed-tomography (CT) scanning. Nuclear magnetic resonance (NMR) was used to measure the water content, and X-ray diffraction (XRD) to analyze the mineralogy. Scanning electron microscope (SEM) was also used to characterize the microstucture. Acoustic-velocity measurements were then made on each set at various confining pressures with the ultrasonic pulse-transmission technique. The results show that confining pressure, water content, and laminations have significant impact on both compressional-wave (P-wave) and shear-wave (S-wave) velocity. Both velocities increase as confining pressure increases. Velocities measured from cores cut parallel to bedding are, on average, 20% higher than those cut perpendicular to bedding. Increasing water content decreases both velocities. The impact of water content on shear velocity was found to be significant compared with the response with compressional velocity. As a result, the water content was found to lower both Young's modulus and shear modulus, which is opposite to the reported results in conventional reservoir lithology. In addition, both P- and S-wave velocities show a linear decrease as TOC increases, and they both decrease with increasing of clay content. The mechanisms that lead to water-content alteration of rock-mechanical properties might be a combined result of the clay/water interaction, the chemical reaction, and the capillary pressure changes.

The understanding of methane adsorption is important for many industrial applications, especially for the shale gas production, where it is critical to understand the adsorption/desorption of methane in pores even as small as a few nanometers. Using small-angle neutron scattering (SANS), we have studied the adsorption of deuterated methane (CD4) into one model mesoporous material, SBA-15, with pore diameter approximately 6.8 nm at the temperature range from 20 to 295 K at low pressure (≈100 kPa). A new scattering model is developed to analyze the SANS patterns of gas adsorption in SBA-15. The surface roughness of the SBA-15 matrix is estimated. The gas adsorption behaviors on the surface regions are extracted from the fitting. The rough surface of the pores is found to retain a large amount of CD4 at the temperature above the capillary condensation temperature (Tc). At temperatures below Tc, the confined liquid and solid methane are estimated to be less dense than the corresponding bulk liquid and solid m...

It is extremely challenging to measure the variation of pore surface properties in complex porous systems even though many porous materials have widely differing pore surface properties at microscopic levels. The surface heterogeneity results in different adsorption/desorption behaviors and storage capacity of guest molecules in pores. Built upon the conventional Porod’s law scattering theory applicable mainly to porous materials with relatively homogeneous matrices, here we develop a generalized Porod’s scattering law method (GPSLM) to study heterogeneous porous materials and directly obtain the variation of scattering length density (SLD) of pore surfaces. As SLD is a function of the chemical formula and density of the matrix, the non-invasive GPSLM provides a way to probe surface compositional heterogeneity, and can be applied to a wide range of heterogeneous materials especially, but not limited to, porous media and colloids, using either neutron or X-ray scattering techniques., Surface heterogeneity significantly influences the properties of porous materials, but remains extremely difficult to characterize. Here, the authors extend Porod’s scattering law from homogeneous to heterogeneous porous materials, allowing for surface variation to be non-invasively probed.

A detailed sensitivity analyses was conducted on an analog simulation model of a hydraulically fractured shale gas well to assess the effects of various controlling parameters on gas rates throughout the production life. Differentiating operational parameters from reservoir properties facilitates high grading shale gas exploration play evaluation and provides guidance to optimize gas production, and manage uncertainties associated with reservoir properties for predictive forecasting. The sensitivity analyses suggest that early-time gas rates are primarily dominated by the characteristics of stimulated rock volume (SRV), while late-time rates are controlled by reservoir properties. The learnings from sensitivity analyses were applied to predict production rates and estimated ultimate recovery (EUR) for a shale gas well in the KSA with flowback data. Early-time wellhead pressure data is very likely controlled by the effect of transient liquid loading and wellbore dynamics, and, as such, may mask the actual reservoir pressure response. While history matching the flow-back period may reduce the uncertainties associated with the quantification of SRV, wellbore dynamics, and initialization, large uncertainties in the estimates of reservoir properties remain the same. This reduces the confidence in predicting long-term production. Therefore, accurate measurement of reservoir properties before massive hydraulic fracturing, independent of history matching the early-time response, is critical for obtaining reliable predictions of gas rates and EUR.

Premature breakthrough and low sweep efficiency during waterfloods result from heterogeneity in the permeability field in a reservoir. Production wells with inflow control valves/inflow control devices (ICVs/ICDs) have the ability to reduce the water-oil ratio by shutting in flow ports with high water cut. Subsequently, this technology has been limited to a response based on detection of water breakthrough at production wells. Deep reading technologies have been reported to be successful in detecting the approaching waterfront before its breakthrough. The objective of this study is to investigate if the technology for early front detection combined with ICVs/ICDs can improve sweep efficiency in horizontal waterfloods. In this study, a synthetic horizontal well pair model is built using a black oil reservoir simulator to study performance of waterflooding in a single layer heterogeneous oil reservoir and to understand the value of information obtained from deep reading technology to control ICVs/ICDs for optimizing waterfloods. The simulation results show that using ICVs/ICDs at the horizontal production well significantly improves sweep efficiency and reduces water production. Early detection of waterfront with deep reading technologies provides incremental oil recovery. An optimum location for waterfront detection exists between the injector and the producer to improve oil production with specified injection and production constraints. Deep reading technologies may also provide valuable information about the mobility field between the well pair to reduce uncertainty in heterogeneity, which can be used to update the geological model for better history matching and forecasting production.

Acoustic velocity measurements are an important non-destructive way to investigate dynamic rock mechanical properties. Water content and bedding-plane-induced anisotropy are reported to significantly impact the acoustic velocities of siliciclastic sandstones and laminated carbonates. This relationship in organic-rich shales however is not well understood and has yet to be investigated. The mechanical properties of organic-rich shales are affected by changes in water content, laminations, total organic content (TOC), and microstructures. In particular, kerogen density that accompanies changes in the composition of the TOC during maturity can significantly influence the acoustic responses within source rocks. To understand how these variables influence acoustic responses in organic shales, two sets of cores from the Eagle Ford shale were investigated: one set cut parallel to bedding and the other perpendicular to bedding. Textures of the samples from each set were characterized using CT scanning. NMR was used to measure the water content, and XRD to analyze the mineralogy. Scanning Electron Microscope (SEM) was also used to characterize the microstucture. Acoustic velocity measurements were then made on each set at various confining pressures using the ultrasonic pulse transmission technique. The results show that confining pressure, water content and laminations have significant impact on both compressional (P-wave) and shear wave (S-wave) velocity. Both velocities increase as confining pressure increases. Velocities measured from cores cut parallel to bedding are on average 20% higher than those cut perpendicular to bedding. Increasing water content decreases both velocities. The impact of water content on shear velocity was found to be significant compared to the response with compressional velocity. As a result, the water content was found to lower both Young's modulus and shear modulus, which is opposite to the reported results in conventional reservoir lithology. In addition, both P- and S- wave velocities show a linear decrease as TOC increases, and also they both decrease with increasing of clay content. The mechanisms that lead to water content alternation of rock mechanical properties might be a combined result of the clay-water interaction, the chemical reaction, and the capillary pressure changes.

Summary In a probe-type formation test, because of the geometry of the wellbore and the sealing effect of mudcake, the flow pattern is not perfectly spherical. To account for the deviation from spherical flow, several geometric correction factors were proposed for different analysis techniques (Steward and Wittmann 1979; Wilkinson and Hammond 1990; Dussan and Sharma 1992; Goode and Thambynayagam 1992; Proett and Chin 1996). A geometric factor is used in formation rate analysis (FRA) (Kasap et al. 1999), a technique used in analyzing a probe test to estimate formation pressure and permeability. Like other geometric correction factors, the geometric factor is a strong function of permeability anisotropy that is generally unknown before a test. When analyzing the test, we would logically assume an isotropic formation and use the corresponding isotropic geometric factor. Consequently, the FRA-estimated permeability does not represent the true spherical permeability. In contrast, the spherical permeability can be estimated from buildup analysis without prior knowledge of permeability anisotropy. Therefore, there is a discrepancy between the permeability estimates from the two analysis methods. In addition, if considered separately, neither FRA nor buildup analysis can decompose the estimated permeability into its horizontal and vertical components. This paper presents the derived numerical values of several geometric factors. Using these factors, we show that the discrepancy between the permeabilities estimated from FRA and from the conventional buildup analysis is attributable to the permeability-anisotropy effect. A correct geometric-factor value must be used to estimate permeability correctly. On the basis of the permeability-anisotropy effect, we present the procedures to estimate horizontal and vertical permeabilities by combining FRA permeability and buildup permeability or by history matching. These procedures are verified with a simulated probe test. Analysis of three actual tests is presented. Introduction A formation test is initiated when a probe from a formation tester is set and sealed against the formation. A measured volume of fluid is withdrawn from the formation through the probe. The test continues with a pressure buildup when fluid withdrawal is halted. Pressure in the tool is continuously monitored throughout the test. The flow pattern during the formation test using a probe is believed to be close to spherical flow. Because of the geometry of the wellbore and the sealing effect of mudcake, however, such spherical flow is imperfect. To account for deviations from spherical flow, several correction factors have been proposed. These correction factors include flow shape factor (Steward and Wittmann 1979; Wilkinson and Hammond 1990; Dussan and Sharma 1992; Goode and Thambynayagam 1992), geometric shape factor (Proett and Chin 1996), and geometric factor (Kasap et al. 1999). Although they have different forms or names, their physical meaning is the same. We use a general term, geometric factor, to represent these correction factors in this paper. The physical meaning of these factors is that because the actual relationship between pressure and flow rate in a probe-type test cannot be described by a spherical-flow equation, these factors are added in the spherical-flow equation to correct for the actual flow relationship. These correction factors are a function of permeability anisotropy, among other parameters. Similarly, the concept of geometric factor is applied to estimate permeability with mini-permeameters (Goggin et al. 1988; Georgi and Jones 1992; Jones 1994, 1997).

Abstract Traditional gravimetry applications are mining/oil exploration surface gravity and formation bulk density borehole gravity logging. Large-scale reservoir saturation monitoring is a new gravimetry application. Substitution of oil or gas by water leads to density changes in large reservoir volumes, which causes time dependent subsurface and surface gravity field variations. This case study presents a complex multilayered reservoir time-lapse gravity data inversion problem. The customary bitmap approach requires many input parameters with a well-known inversion ambiguity. This ambiguity is in this work reduced by introducing a priori information obtained by biasing the inversion with history matched reservoir simulation output. A synthetic gravity data set was first generated by forward gravity modeling using the simulation saturation output from an onshore giant Middle Eastern oil field. By analyzing the simulation saturation data, the reservoir layer specific behavior of the water saturation and oil-water flood front was understood and used as a priori input in the optimized inversion algorithm used to fine-tune the predicted location of the oil-water flood front on the basis of the synthetic gravity data. Numerical examples with associated graphics demonstrate how inversion and accuracy estimates work for this data set. The proposed inversion technique will depict differences from the history matched simulation saturation and the gravity data; therefore, actual field gravity data will allow the enhancement of the reservoir simulation history match precision. The presented inversion of time-lapse gravity data demonstrates a substantial potential for the 4D microgravity. Since borehole gravity sensors are less affected by near surface changes, the borehole gravity data has significantly improved spatial resolution and much higher measured ? in the gravity signal resulting from the fluid substitution of hydrocarbons by water. In the presented inversion work, the maximum synthetic time-lapse ? gravity signal at the top reservoir was 18 times greater in magnitude compared to the predicted maximum surface time-lapse gravity signal amplitude. For microgravity to be a serious alternative for inter-well hydrocarbon saturation mapping for oil fields under waterflood, the borehole microgravity hardware development needs to be given significant R&D priority to reduce the diameter of the borehole gravity tool and improve gravity meter precision for both surface and borehole sensors. Introduction Geology and reservoir engineering describe the subsurface reservoir by utilizing sparse well data. As only a very small fraction of the subsurface can be observed through cores, well logs and well production data, the inter-well reservoir characterization is very challenging, especially in heterogeneous or fractured reservoirs, where simply interpolating wellbore data is not adequate to infer fluid distribution. At present, dynamic changes between wellbore control points is only understood via matching reservoir simulation models to reproduce the acquired well data. In the Journal of Petroleum Technology (JPT) May 2011 issue, the Society of Petroleum Engineers (SPE) Research & Development (R&D) Committee defined the five grand R&D challenges facing the oil and gas industry (Judzis et al. 2011), which included higher resolution subsurface imaging of hydrocarbons. In a follow-up JPT article, Neal and Krohn (2012) identified the most advanced technology options offering a solution to the inter-well hydrocarbon mapping problem as:3D/4D Seismic: surface, borehole and cross-well acquisition;Electromagnetic: borehole to surface and crosswell;Microgravity: borehole and surface acquisition; andNanotechnology.

Gravimetry is a physical method with a large depth of investigation. Traditional applications include surface gravity observations for mining and oil exploration and borehole gravity logging for investigating formation bulk density. A new application of gravimetry is large-scale reservoir saturation monitoring. Replacement of oil or gas by water leads to density changes in large volumes of the reservoir, which causes changes of the gravity field down hole as well as on the surface. Since borehole gravity sensors are closer to the reservoir than for surface acquired gravity data, borehole gravity data has better spatial resolution and are less affected by near surface changes. This paper focuses on the problems of inversion of time-lapse gravity data for complex multilayered reservoirs and estimation of the accuracy of the reconstructed oil-water flood front. The traditional bitmap approach (dividing the reservoir into blocks) requires a huge number of parameters and leads to the well-known inversion ambiguity. This ambiguity can be reduced by introducing a priori information. The basic idea of the presented approach is to obtain this a priori information by biasing the inversion with output from a history matched reservoir simulation data set. In this case, reservoir simulation saturation data from an onshore giant Middle Eastern oil field was used as input. By processing the simulation saturation data, it was possible to understand the behavior of the water saturation and oil-water flood front in the different layers of the reservoir. Using this knowledge, a 3D model of density changes was introduced. This model formed the basis of the optimization inversion algorithm used to fine-tune the actual location of the oil-water flood front on the basis of gravity data. Numerical examples demonstrate how inversion and accuracy estimates work for data obtained from a realistic reservoir simulation. The proposed inversion technique will depict any differences from the history matched reservoir simulation saturation output and the gravity data; thus, the gravity data will allow enhanced precision of the reservoir simulation history match.

Despite the extensive use of new technologies for the exploration of unconventional organic rich shale resources and vast work on the prediction of the quantities of light hydrocarbons (Gas in Place, GIP), many questions remaining concerning the storage, migration and production of natural gas in unconventional gas shales. There is a need for a deeper understanding of the physics and chemistry of light hydrocarbon molecules within the micro- and nanopores in the kerogen. A number of research results have been published that emphasize the importance of nanopores in kerogen for the unconventional shale resource plays, and our previously published laboratory results have shown that it is possible for gas to condense into liquid in the nanopores of kerogen once the Kelvin equation is satisfied. Petrographic features of several Woodford shale core samples were studied using Scanning Electron Microscopy (SEM) on splintered and Focused Ion Beam (FIB) milled surfaces. The morphologic features and the connectivity of the pores in kerogen were recorded. We performed gas condensation experiments on these samples using hexane and found that there is a close relationship between the amount of condensed gas and the porosity within the kerogen. Based on the nanopore physics the flow of gas within the organic matter will be significantly impacted by capillary condensation. Nuclear Magnetic Resonance (NMR) measurement on the samples with condensed gas components show that the relaxation is also significantly affected by the properties of the nanopores within the kerogen of the unconventional shale samples and must be properly accounted for in the formation evaluation.

All Shale Gas reservoirs are not the same. There are no typical Tight Gas reservoirs. These two statements can be found numerous times in the literature on shale gas and tight gas reservoirs. The one common aspect of developing these unconventional resources is that wells in both must be ‘hydraulically fractured’ in order to produce commercial amounts of gas. Operator challenges and objectives to be accomplished during each phase of the Asset Life Cycle (Exploration, Appraisal, Development, Production, and Rejuvenation) of both shale gas and tight gas are similar. Drilling, well design, completion methods and hydraulic fracturing are somewhat similar; but formation evaluation, reservoir analysis, and some of the production techniques are quite different. Much of the experience in shale and tight gas has been developed in the US and in Canada, to a lesser extent; and most of the technologies that have been developed by operators and service companies are transferable to other parts of the world. However, the infrastructure, including equipment and service company availability, governmental regulations, logistics, processing, environmental considerations, and pricing are not the same as in the US. This may impact the rate of the technology transfer as well as the selection of some of the technology. This paper is focused on operations challenges, technologies, and experience associated with shale and tight gas projects. It is likely that environmental concerns and the drive to reduce development costs of tight and shale gas reservoirs will drive new approaches to the development of these reservoirs in China, Latin America, Middle East, North Africa, and other parts of the world.

Deepwater operations (with high rig spread rates) like those offshore Brazil require an operator to very carefully consider the benefit-versus-cost of a full coring acquisition program. Yet, core-based information is invaluable in the exploration phase of a field's potential, and the basis of thoroughly understanding reservoir rock potential (petrophysics) is founded on these core measurements. With the drive for cost efficiency, conventional full-core acquisition is often curtailed and subsurface teams must rely on percussion or rotary sidewall core samples. This choice is made even though it is known that for many core analysis measurements, the accuracy of the measurement is directly proportional to the pore volume. A new rotary sidewall coring technology applicable for deepwater environments has been applied offshore Brazil that enables the recovery of more than three times the core volume when compared to cores recovered with standard rotary coring tools. The resulting increase in pore volume positively impacts the accuracy of the core porosity measurement and other measurements that depend on pore volume (e.g., capillary pressure, water saturation, and SCAL measurements, in general). Recovery of up to 60 samples during a single trip in the well is achievable, enabling a good lithology sample spread in one acquisition. Acquisition time per core is more than three times faster that of the previous-generation rotary coring tools, resulting in significant reduction of coring time, especially for offshore operations. Coupled with a new bit design, optimized to take advantage of the increased rotational speed, cores can be cut at even higher levels of overbalance pressure (> 1,000 psi [6.89 MPa], depending on porosity and permeability). The ability to take up to 60 larger-volume cores in one run provides operators, like those in deepwater operations of Brazil, the flexibility to continue to vary the design of core acquisition programs to meet the benefit-versus-cost dilemma of full-core acquisition. They also enable much better contingency data gathering if full-core programs are not successful.

Summary Induced gamma ray spectroscopy (IGRS) logs from two cyclic-steam-stimulation observation wells in Cold Lake were analyzed to determine the vertical resolution and repeatability of data derived from gamma rays of inelastic and capture neutron reac tions. Time-series analysis, a technique that uses the Fourier representation of the log data, was used to quantify the vertical resolution and the signal/noise characteristics of various IGRS log curves and to compute the coherence vs. spatial frequency of data collected on multiple IGRS passes. The coherence function ranges from 1.0 for perfect repeatability to 0.0 for incoherent noise. Because no real variations in the measured data were expected for the 12- to 24-hour data-collection period, any deviation of the coherence function from 1.0 is attributed to incoherent noise. Generally, coherence is high at low frequencies (large vertical scales) and low at high fre quencies (small vertical scales). By noting the frequency at which the coherence level decreases to the expected value of random noise, we can quantify the vertical resolution of a log curve. Data analysis from these wells indicates that both the vertical resolution and repeatability of individual capture and inelastic curves differ. We found that the H-yield and capture curves have the highest vertical resolution (≈0.3 m) and the best signal/noise ratios (FSN≈30:1). In contrast, the capture Ca and Si yields are of significantly lower quality (FSN≈2:1). Only a small difference exists between the vertical resolution of the inelastic C (1.0 m) and O (1.3 m) yields, but the FSN the O yield is only one-half that of the C yield. Fortunately, the vertical resolution and the repeatability of the C/O ratio, FCO, are determined primarily by the quality of the inelastic C data. Specific to our application of monitoring heavy-oil saturations during cyclic-steam stimulation in a relatively uniform, high-porosity unconsolidated sand, we developed a simplified FCO interpretation that does not rely on the elemental yields from capture data. This linear model permits us to assess the uncertainties in computed saturations from the statistical noise in the inelastic FCO data.

Abstract For years petrophysicists interpreted logs as if all formations were locally homogenous and isotropic. They did this even though they well understood that sedimentary deposition occurs layer by layer, making transversely isotropic, TI, media the rule rather than the exception in sedimentary geology. With the widespread availability of multi-component induction logging technology petrophysicists are more willing to use TI resistivity models (i.e., Rh and Rv). Generally, sediments buried a few hundred meters or more are subject to a principal stress aligned with the overburden. In many environments, depending on mechanical properties, this leads to bedding perpendicular fractures, which can give rise to biaxial anisotropy in the macroscopic petrophysical properties. We have developed resistivity models for laminated sand-sale formations in the presence of drilling- induced and natural fractures. The principal resistivities Rx, Ry, Rz are expressed as a function of horizontal and vertical resistivities of unfractured formation, fracture porosity and resistivity of fracture which is the resistivity of mud filtrate in the case of drilling induced fractures or the connate water resistivity and saturation in the case of natural fractures. These models allowed us to study the effect of fractures on the three principal resistivities as a function of laminated shale content and as a function of fracture porosity for both drilling induced and natural fractures. The combined three-step analysis of measured principal resistivities based on the modular concept allows a separation and quantification of the two anisotropy sources: fracturing and lamination. The analysis based on the three principal resistivities provides an estimate of fracture porosity, resistivity of the porous sand fraction (without fractures) and water saturations. We have also developed an inversion algorithm for the biaxially anisotropic formations that reliably determines three principal resistivities from multi-component induction measurements. First, in the least-square inversion the multi-frequency focused magnetic field tensor is rotated to the principal coordinate system. This rotation is characterized by three angles: ?, ?, and ?; and three principal, diagonal magnetic field components Hxx, Hyy, and Hzz. After the three angles and three principal components are determined, we recover principal formation resistivities using a fast inversion algorithm based on a look-up table approach. To validate the theory and algorithms described above, we have simulated the multi-component induction measurements in thick biaxially anisotropic layers for various sets of parameters and used the software to process the data. The new approach was also applied to the real measurements acquired in the well with drilling induced fractures and as a result principal formation resistivities, fracture orientation, and fracture porosity were reliably determined. Introduction Early resistivity measurement pioneers realized that the earth is not homogenous and isotropic (C. Schlumberger 1920; Schlumberger et al., 1934). However, physics limited measurements primarily to those sensitive to Rh (e.g., in the plane normal to the borehole) and it was predicted that borehole effects would prevent resistivity anisotropy measurements (Moran and Gianzero 1979) and, even after the first successful measurements (Kriegshauser 2000) were reported concerns were raised about complicated borehole effects (Anderson 2002). Additional background information and review of multicomponent induction technology can be found in Rabinovich et al. (2007).

NMR logging techniques have proven to be useful tools for a variety of formation rock properties and fluid typing applications. In the last decade, numerous improvements have been made both to multi-frequency NMR logging instruments and to data acquisition methods that have significantly enhanced the data quality and expanded the NMR logging applications envelop. On the other hand, these more versatile acquisition methods collect a large quantity of data that may seem overwhelming to most non-expert NMR users. To overcome the complexity of NMR logging and facilitate the wellsite decision-making, we have developed a number of simple, robust NMR log-based indicators for identifying hydrocarbon gas or oil, for detecting borehole rugosity contamination, and for recognizing vugs in carbonate reservoirs.

The SPWLA just changed the name of our Society to reflect the changes in our job and industry. The membership overwhelmingly approved changing the name from the Society of Professional Well Log Analysts to the Society of Petrophysicists and Well Log Analysts. We changed the meaning of the letter “P” from Professional to Petrophysicist not because we are less professional but because our jobs involve more than just the evaluation of well logs. As the use of MWD and LWD measurements increased, we simply ignored the means of sensor conveyance. However, by changing the meaning of “P” from Professional to Petrophysicists, we recognize that we are involved with many sources of data including cores and logs, and that we use more than charts, nomographs and computers to do our jobs. We use and develop petrophysical models that allow us to more completely evaluate formations and reservoirs. The SPWLA is a nonprofit corporation dedicated to the advancement of the science of petrophysics and formation evaluation, through well logging and other formation evaluation techniques and to the application of these techniques to the exploitation of gas, oil and other minerals. Founded in 1959, SPWLA provides information services to scientists in the petroleum and mineral industries. The Society serves as a voice of shared interests for our profession, plays a major role in petrophysical education, and strives to increase the general awareness in the Oil and Gas Industry and the scientific community of the contributions of petrophysics. In this short article, I will summarize the rich history of the SPWLA, review some of the present activities, and look towards what should be a very promising future.

Measurement of resistivity anisotropy is critical to reserve estimation and permeability anisotropy determination is key to efficient hydrocarbon exploitation. It is now possible to measure resistivity anisotropy with new wireline, multi-component induction hardware. However, it is difficult to directly measure or determine permeability anisotropy. Thus, it would be beneficial to be able to relate resistivity and permeability anisotropy and predict kv:kh from Rh:Rv (where kv and kh are the vertical and horizontal permeabilities, and Rv and Rh are the vertical and horizontal components of formation resistivity). We know that both resistivity and permeability anisotropy are scale dependent. In our study, we define three scales for formation anisotropy properties: The Micro-scale relates directly to the properties of individual components (e.g., sand and shale). The Macro-scale is an intermediate scale defined by the vertical resolution of the measurement tools. Most logging tools are not capable of resolving the individual lamina in laminated sand-shale sequences. In this case, the "macroscopic anisotropy" can be described by the well-known rules for conductors connected in parallel and/or in series. At the Reservoir-scale, anisotropy is governed by interconnected channels formed by gaps in the relatively impermeable shale layers. We have developed a numerical simulator that allows us to model at all scales the anisotropy for resistivity and permeability for arbitrary three-dimensional, periodic structures. The simulation results have been verified with known analytical solutions. With this model we have explored reservoir-scale anisotropy as a function of the lateral extent of the shales and sands. By varying the thickness of the sands and shales, we investigated the effect of net-to-gross on the electrical and permeability anisotropy. From our studies we conclude that the relationship between resistivity and permeability anisotropy is not trivial. On the smaller scales it is controlled by the spatial distribution of the pore-space properties and on the larger reservoir scales by the spatial distribution of the sand bodies and gaps in the shale barriers. We show both numerically and theoretically for 2D structures that resistivity and permeability anisotropy are identical for cells with inverse property contrasts. This implies that fluid and current flow anisotropy are equal. However, this does not hold for every 3D geometry and in general there is no correlation between permeability and resistivity anisotropy on the macroscopic or reservoir scale for laminated sand-shale systems.

Summary Cost-effective, efficient production of hydrocarbons depends on accurate reserves estimates, reservoir architecture, and hydrocarbon distribution. In addition, a complete reservoir description, including both horizontal and vertical permeability, is critical to efficient development strategy. Hydrocarbon recovery efficiency depends on many factors, but one key parameter is the ratio of vertical to horizontal permeability. There are numerous ways to estimate permeability. It is now possible to estimate permeability from continuous formation evaluation measurements. However, it remains difficult to determine directional permeability. Nuclear magnetic resonance (NMR) logs are used routinely to estimate permeability, but NMR-derived permeability is based on scalar properties (e.g., ϕ, T2 distributions from NMR, and bulk volume irreducible water) and is inherently a scalar property itself. Few formation evaluation measurements provide directional information. Dip and image logs provide bed thickness and layer dip information, while the multicomponent induction instrument (3DEX*) and crossed-dipole shear-wave acoustic tools provide direct measurements of macroscopic formation anisotropy. In this paper, we explore theoretically and with real data the computation of permeability anisotropy. We use laminated sand models as well as macroscopic models based on the resistivity anisotropy measurements to estimate kV:kH ratios. In addition to multicomponent induction data, we explore stand-alone and joint interpretation of NMR property variations to predict the macroscopic reservoir permeability anisotropy.

Summary New induction-logging hardware makes it possible to obtain both resistivity and resistivity-anisotropy data. Resistivity anisotropy, the ratio of vertical to horizontal resistivity, is the macroscopic effect of thinly layered formations in which logging tools have insufficient vertical resolution to properly resolve the individual beds, or laminae. Generally, there are two special types of layering. Laminated shaly sands. The sediment consists of thin-bedded sand/shale sequences (anisotropy in these sands originates from the contrast of shale and sand resistivity). Finely layered anisotropic sands. The sand is composed of layers of different grain sizes/sorting (anisotropy in these sands originates from the resistivity contrast associated with the different water saturation). The interpretation of conventional resistivity data is well understood. However, interpretation of vertical resistivity and resistivity anisotropy is not well understood and is often counterintuitive. We have used forward modeling to illustrate the effects of porosity variability in layered formations. For example, we have investigated the porosity-layering effect, which varies from an average porosity of 20 p.u. by +/− 5, 10, and 15 p.u. Three types of layering were considered: graded bedding and square- and sin2-porosity variation with depth. The modeling shows that sharp bed boundaries create the maximum resistivity anisotropy for any two component resistivity distributions. The new induction-logging hardware comprises three mutually orthogonal, transmitter-receiver coil configurations that measure all data necessary to derive both resistivity and resistivity anisotropy of the formation in vertical, deviated, and horizontal wells. Simple models illustrate the physics, and the tools' capabilities are demonstrated with a synthetic example. Based on the petrophysical analysis of porosity contrast and layering type, a resistivity model is constructed, and the tool responses of this model are computed. With inversion techniques, both resistivity and resistivity anisotropy can be recovered.

Accurate petrophysical evaluation of deep water turbidites composed of thin bedded sand-shale sequences is crucial in the economic decision to explore, develop, and produce these reservoirs. Traditional laminar shaly sand saturation equations are based on a parallel conductivity model that typically results in significant underestimation of in-place hydrocarbons. Electrical anisotropy is the macroscopic effect of thinly layered sedimentary formations in which logging tools have insufficient vertical resolution to properly resolve individual beds or laminae. Utilizing anisotropy in the saturation analysis transforms the classic "low resistivity shaly sand problem" into a tensor petrophysical model. The tensor shaly sand saturation model is applied to both simple and complex reservoir types with the following results: Simple laminated sand-shale model: Forward model calculations for the resistivity tensors demonstrate the effect of the model variables on net-to-gross, shale resistivity, sand resistivity, and sand porosity. Sand saturation determination is dominated by the vertical component and shale resistivity is dominated by the horizontal component.Complex anisotropic sand model: Forward modeling using alternating fine-coarse grain size distributions within a sand body demonstrates the effect of pore size changes resulting in capillary-induced water saturation profiles. Tensor components for anisotropic sands are presented as an integral expression for any water saturation distribution. The following response of the Resistivity Index (RI) is noted:RI vs. Sw relationship does not follow an Archie-type power lawRI vs. Sw relationship is different for the parallel and perpendicular laminated resistivity components. The tensor water saturation equation utilizing electrical anisotropy is demonstrated to be theoretically correct for both the laminar sand-shale reservoirs and complex anisotropic sand reservoirs. The significant advantage of the tensor model is a more accurate water saturation determination that minimizes the errors inherent in traditional parallel conductivity saturation equations.

Abstract Gravity segregation between water and a hydrocarbon based solvent during miscible flooding has been observed at the Judy Creek Beaverhill Lake (BHL) 'A' Pool tertiary flood. The solvent override results in bypassing of potential miscible reserves and decreases ultimate oil recovery. An effort to improve overall pool economics through maximizing oil recovery and more efficient solvent utility was sought. A vertical sweep pilot was undertaken to identify optimum pattern sizes by defining the shape and size of pattern sizes by defining the shape and size of the solvent-water comingled region in the reservoir. It was found that the gravity segregation model defined by Stone was representative of the solvent-water comingled zone. A reduction in pattern size was seen to improve tertiary oil recovery levels. This has bolstered a pattern reconfiguration scheme to maximize ultimate oil recovery from the field. Introduction The Judy Creek oil field is located about 200 km northwest of Edmonton, Canada (Figure 1). The field was discovered in 1959, and original oil in place is estimated at 792 MMSTB (126 × 10 m). place is estimated at 792 MMSTB (126 × 10 m). Figure 2 is a structure map on the top of this large Devonian reef. The reef covers an area of about 32,000 acres (13,000 ha). Its highest point is located along the northeastern edge, from which the reef dips toward the southwest. A structural cross-section (Figure 3) shows the reef in profile. The atoll-like limestone reef has a profile. The atoll-like limestone reef has a gross thickness of up to 230 feet (70 m). Some internal markers defined by core studies, are shown to subdivide the reef into five cycles (" R1,…,R5") of growth. Pay zones are best developed on the higher energy reef margins, while the reef interior lagoon is characterized by discontinuous pay zones. Figure 4 outlines net pay and shows the thickest pay interval along the pay and shows the thickest pay interval along the northeast reef margin. This portion of the reef is characterized by thick, continuous pay zones and is referred to as the High Productivity Area (HPA). The pool was initially developed on 160 acre (64 ha) well spacing and depleted under solution gas drive. A peripheral water injection scheme was implemented in 1964, and oil production -levels peaked in 1973 at about 70,000 bbl/day (11,000 peaked in 1973 at about 70,000 bbl/day (11,000 m /d)(Figure 5). Production declined until 1975 when a pattern waterflood scheme and infill drilling program temporarily arrested the decline. Production again began to decline until the miscible flood was instituted. Hydrocarbon solvent (ethane based) injection began in May, 1985, and by year end 16 patterns were on solvent injection. As of December, 1989, there were 36 patterns which are or have been solvent flooded. patterns which are or have been solvent flooded. The initial design of the flood was to inject a 15 percent continuous hydrocarbon pore volume (CHCPV) percent continuous hydrocarbon pore volume (CHCPV) slug of solvent followed by a 20 percent CHCPV slug of chase gas at a water-alternating-gas (WAG) ratio of 1.0. The flood was designed to employ existing waterflood pattern configurations of inverted nine spots. The general, these were 320 acres (128 ha) in size. Production response to the miscible flood is illustrated in Figure 6. The high productivity area (HPA) had been undergoing solvent flooding since May 1985. High solvent injection rates are possible in this area and have resulted in maturation of bank sizes. Miscible fluid movement from injectors to producers had been extensively studied through an producers had been extensively studied through an ongoing program of production and injection well logging. P. 529

Modal properties of Antarctic Intermediate Water (AAIW) are determined from bivariate distribution diagrams for two regions in the southeast Pacific and two regions in the South Atlantic. The volumetric potential temperature-salinity diagrams reveal distinct differences between the intermediate waters of the southeast Pacific and the South Atlantic. The intermediate waters of the, southeast Pacific are more homogeneous than their counterpart in the South Atlantic. The potential temperature and salinity properties of the large volume mode intermediate water in the southeast Pacific are identical to those of the coldest variety of McCartney's (1977) Subantarctic Mode Water (SAMW). It is evident from volumetrically weighted-average properties that the intermediate water of the South Atlantic is primarily colder (∼1°C), denser (∼0.1 mg cm−3) and oxygen poorer(O.5 ml l−1) than the intermediate water of the southeast Pacific. If it is assumed that no AAIW formation takes place in the South Atlantic out...

Summary A method for determining the relative values of the low-order Gauss coefficients for the palaeomagnetic field from inclination data only, i.e. in the absence of declination and intensity information, has been used to extend the analysis carried out by Creer, Georgi & Lowrie to include the core data published by Opdyke & Henry. The 20 regional average Quaternary palaeomagnetic inclination directions given by Creer et al. were combined with 12 new regional average data points derived from the deep-sea sediment core data published by Opdyke & Henry to form a grand population of 32 inclination directions. The analysis was carried out to determine both the second-order and third-order coefficients. It was found that the normalized amplitudes of the second-and third-order terms dropped of€ at least as rapidly as those of the present-day field. The Cartesian co-ordinate positions of the eccentric dipole for the grand populations were found to be in general agreement with those found by Creer et al. The input data were also perturbed to determine the sensitivity of the offsets to errors in the data. It was generally found that the offset along the rotation axis was least affected by input errors. Various authors have used palaeomagnetic observations to determine the nature of the Earth's palaeomagnetic field. Watkins (1972) has proposed that hemispherical differences in Brunhes inclination data can best be accounted for with double axialdipole model. Wilson (1970) proposed that the inclination data for the Quaternary and upper Tertiary can best be represented by an axial dipole displaced from the geocentre along the rotation axis. In terms of standard spherical harmonic analysis Wilson determined the values of 8,' and 8,'. Creer, Georgi & Lowrie (1973) developed three new methods to determine all Gauss coefficients of degree one and two (g,', . . ., h,'). These terms in turn were used to calculate the position and orientation of a single dipole displaced from the geocentre, for the Quaternary and late Tertiary geomagnetic field.

A non-destructive temperature calibration system for expendable bathythermographs (XBT) is described. A transfer standard technique has been used to estimate XBT thermistor probe-to-probe temperature variability. One-point calibration results suggest that a standard deviation of 0.025°C is typical at 10°C. Additional calibration data from nine XBT thermistors suggest that probe-to-probe temperature variability is largest at 0°C (ca. 0.03°C) and decreases uniformly to a minimum at 30°C (ca. 0.01°C).

Some of the characteristics of intrusive finestructure observed in oceanic fronts suggest that salt fingering is active in the intrusions. An extension of Stern's 1967 study of the stability of a thermohaline front to intrusive finestructure driven by salt fingers is presented to investigate this hypothesis. Intrusions are found to grow due to the salt finger induced density fluxes even in the presence of small scale momentum dissipation. The presence of this dissipation defines a fastest growing mode for the disturbance which has physical characteristics not unlike those observed in oceanic fronts. The model results do not agree well with the laboratory studies of intrusions. For many fronts, the model requires initial perturbations in the front which can support salt fingers. Linear internal waves are investigated to determine if they can provide the initial perturbation. It is shown that, away from the equator, the interaction between internal waves and intrusions is weak because of a mismatch of time scales. Finally, growing intrusions are shown to flux heat, salt and density across fronts. The senses of these fluxes are to run down the lateral gradients of many oceanic fronts.

Continuous conductivity-temperature-depth-dissolved-oxygen (CTD) data are used to investigate the spatial distribution of fine and microstructure between the Azores and Flemish Cap. The CTD data are used to calculate a conductivity-microstructure Cox number. This indicator summarizes microstructure variance from the 0.08–2 m vertical wavelength range. The CTD data are also used to calculate the finestructure-temperature Cox number. Finally, the fine and microstructure data are combined to calculate lateral flux and flux divergence for the waters east of the Atlantic Current. The distribution of the conductivity Cox number indicates that vertical mixing is more intense above the base of the main thermocline (5°C isotherm) than below it, and that mixing is more prominent near the North Atlantic Current than farther east. Stations near the front indicate elevated conductivity Cox numbers associated with intrusive features. The hydrographic sections and the finestructure data reveal the presence of i...

The component of the FDRAKE-75 data obtained by the R/V Conrad in the western Scotia Sea reveals a definite sequence of thermohaline stratification zones encountered on passing from Antarctic to Sub-antarctic waters. A Polar Front Zone, displaying multiple temperature minima, separates the Antarctic Zone, characterized by a single intense T-min above 200 m, from the Subantarctic Zone with its nearly isohaline layer from 100 m to over 400 m. The Antarctic Zones of the Weddell and the Scotia Seas aye separated by a cold, relatively homogeneous zone situated in the southern Scotia Sea called the Weddell-Scotia Confluence. The boundaries of the Polar Front Zone are highly meandered and isolated eddies of Subantarctic water may occur within the zone. The main axis of the Antarctic Circumpolar Current apparently lies close to the Subantarctic boundary of the, Polar Front Zone, while a secondary axis is associated with the southern limit of the Polar Front Zone. Inspection of the Islas Orcadas and Melvi...

Antarctic Intermediate Water and Subantarctic Mode Water are studied by examining their modal density and modal salinity characteristics around Antarctic. The study focuses on 15 regions between 40 and 45°S. Circumpolar distributions for the cores of Antarctic Intermediate and Subantarctic Mode Water and potential temperature-salinity diagrams provide a detailed description of the water masses. The modal salinity and density change gradually across each of the three oceans, presumably due to the alteration of a single water mass. Large changes occur in the transition regions in the Drake Passage, south of Africa, and south of New Zealand. These large changes are due to the presence of distinctly different water masses. Thermohaline finestructure is associated with the water mass transitions. The finestructure intensity between the 27.10 and 27.40 σθ isopycnals is quantified. Although continuous temperature-depth data are not available for the entire region the study indicates that the most intense finestructure occurs in regions of large water mass contrast and decreases by an order of magnitude away from them. Increased vertical temperature gradient variances were observed near a 100-km diameter eddy south of New Zealand.

Data from 137 new hydrographic stations are used with older hydrographic data to construct horizontal charts of potential temperature at 4000 m and the depth of the 0°C potential temperature surface for the southwestern South Atlantic. The data are also used to construct seven potentials temperature sections and to calculate bottom water transport. From the horizontal charts it is inferred that the abyssal circulation in the Argentine Basin and its southward extension consists of several distinct gyres. The most intense abyssal circulation is in the western Argentine Basin. It is suggested that these bottom waters are renewed by northward flow through the East Falkland Channel from the Georgia Basin. The Georgia Basin provides the most direct conduit to the western Argentine Basin for the cold, fresh bottom waters found in the vicinity of the South Sandwich Trench. The horizontal charts also indicate a southward flow from the Argentine Basin into the Georgia Basin of warmer bottom waters through the East Falkland Channel. These waters are found along the southern flank of the Falkland Fracture Zone and the eastern flank of the Islas Orcadas Rise. The vertical potential temperature sections illustrate the baroclinic structure of the western boundary currents over the South Sandwich Trench and along the Argentine Continental Slope. The calculated northward transports for waters with potential temperatures less than 0°C are largest (18 x 106 m3 s−1) at the southern end of the South Sandwich Trench just north of the Weddell Sea. The transports decrease to 5 x 106 m3 s−1 at the northwestern end of the trench. The major flow of cold bottom water into the Argentine Basin appears to be through the Georgia Basin, with 1 to 3 x 106 m3 s−1 flowing through the Falkland Channels. A reference level is chosen in the Argentine Basin that is coincident with the depth of the 0°C potential temperature surface that on the average is 2000 m deeper than that proposed by DEFANT (Wissenschaftliche Ergebnisse der Deutschen Atlantischen Expedition auf dem Forschungs- und Vermessungsschiff “Meteor”, 1925–1927, 6 (2, 5), 191–260, 1941) and used by Wust (Wissenschaftliche Ergebnisse der Deutschen Atlantischen Expedition auf dem Forschungs- und Vermessungsschiff “Meteor”, 1925–1927, 6 (2, 6), 261–420, 1957). The calculated transports for the deep and abyssal boundary currents in the western Argentine Basin are small (2 x 106 m3 s−1), less than one-tenth that calculated bu Wust (1957) for the bottom waters.

Summary Methods of computing relative values of the first eight Gauss coefficients of the geomagnetic field from directional data only are described. The purpose is the analysis of the palaeomagnetic directions for which intensity data are normally lacking and which are characteristically subject to considerable experimental uncertainty of the order of 5°. Four solutions have been derived of the basic equations of degree n≤ 2 involving declination D and inclination I by combining (i) the X and Y, (ii) the Z and Y, (iii) the Z and X, and (iv) the Z and H field components. Various populations of Quaternary and Neogene palaeomagnetic directions have been analysed in this way. Improved fits of computed to observed field directions are obtained by grouping the directions derived from individual palaeomagnetic studies to form regionally averaged control points which are more uniformly distributed geographically. The Z-H and Z-X solutions give notably better fits to the observations than the X - Y solutions. Our results are expressed in terms of a single eccentric dipole, the position of which may be obtained from the values of the first eight Gauss coefficients of degree n≤ 2. Analysis of different populations of Quaternary and Neogene data yield a persistent and systematic displacement of the eccentric dipole into the Pacific and northern hemispheres by some 150 km. Analyses of sub-populations of data corresponding to northern, southern, Pacific and ‘continental’ hemispheres reveal appreciable differences in the position of the eccentric dipole suggesting (i) that the Quaternary field cannot be well represented by a single-point source of dipoles and quadrupoles, and (ii) that harmonics of degree n > 2 have been persistently stronger in the continental than in the Pacific hemisphere throughout the Quaternary, just as for historic epochs.

Prepared for the National Science Foundation - Office of International Decade of Ocean Exploration under Grant OCE-78-22223.

Prepared for the National Science Foundation - Office of International Decade of Ocean Exploration under Grant OCE-78-22223.

Accurate reserve estimates for unconventional shale gas reservoirs are critical to their economic assessment and field planning. Reserves are typically assessed with log and core measurements. Much of the log-derived information is validated with cuttings and core data. In particular, adsorption isotherms are measured in the laboratory and used to estimate ultimate recovery. Accurate shale gas reserve estimations require a storage model that incorporates the physics of small scale, i.e., nanopores. This model is critical for the interpretation of log data and the prediction of long-term production and ultimate recovery. Current models partition gas into two parts: gas adsorbed on the pore surface with density comparable to liquid and free gas in the shale rock pores and natural fractures. Such a storage model, however, fails to consider the extremely favorable conditions for capillary condensation in the kerogen-rich rocks: pores in the kerogen range from a few nanometers to a few hundred nanometers and the pore surfaces are strongly oil wet. These two conditions are highly favorable for capillary condensation to occur; consequently, a significant amount of hydrocarbon probably exists in kerogen pores in the liquid state. Capillary condensation in shale gas core plugs has been verified in a laboratory study and significantly more hydrocarbons were observed than one would have expected in a traditional model that does not include capillary condensation. We propose a new shale gas storage model for organic-rich shale rocks that accounts for capillary condensation. In this model part of the ‘gas’ exists in liquid phase inside kerogen pores. Capillary condensation is easy to model for single-component hydrocarbons. Under reservoir conditions, the hydrocarbons are usually a mixture of multiple components. This paper presents the method and theoretical result for estimating the total hydrocarbon volume for hydrocarbon mixtures in organic rich shales in the presence of capillary condensation.

Volumetric analysis is used to quantify the observed changes in the Circumpolar Deep Water (CDW) potential temperature/salinity relationship along the axis of the Antarctic Circumpolar Current. A marked increase occurs in the CDW potential temperatures and salinities in the South Atlantic. However, the vertical density distribution is not significantly affected: The volume of water in the deep water density class intervals remains virtually unchanged. Lateral mixing with the warmer and saltier North Atlantic Deep Waters (NADW) and the colder and fresher Antarctic deep waters appears responsible for this change. Temperature and salinity inversions have been observed on continuous salinity-temperature-depth soundings in much of the South Atlantic. This fine structure, presumably the signature of lateral mixing and not of internal wave origin, is particularly evident in the southwestern Argentine Basin, where 0.5°C temperature inversions with 50–200 m vertical scales are found at the depth of the NADW/CDW confluence, between 1500 and 2500 m. To quantify the intensity of the fine structure the temperature-gradient variance in the 32–256 m vertical wavelength band is calculated for data from the southwest Argentine Basin the Drake Passage, Scotia Sea, the central and eastern Atlantic, and the southwest Indian Ocean. The largest variance levels occur in the Argentine Basin, the smallest in the Drake Passage, while those in the central Atlantic are intermediate. The temperature-gradient variance data from the Argentine Basin are then used to estimate the lateral temperature flux in the NADW/CDW confluence with a statistical model developed by Joyce (1977). The calculated quantities are small; the lateral temperature flux is of the order of 4 × 10−4°C m s−1 and the lateral diffusivity of order 40 m2 s−1. The data are also used to calculate heat flux divergences. The close agreement between the heat flux divergence calculated from the temperature changes of the CDW core and the divergence calculated with the fine structure data suggest that lateral mixing accounts for the large-scale property changes observed in the CDW core.

Temperature and salinity data from a repeated salinity-temperature-depth station and temperature profiles from three expendable bathythermograph experiments are used to investigate both the spatial and the temporal characteristics of fine structure observed in the Antarctic Polar Front Zone. The fine structure was found to evolve considerably on time scales of 1 hour and less. From an experiment designed to elucidate the spatial scales of the fine structure, a marked anisotropy was revealed, suggesting that the temperature structures were elongated filaments aligned with the front. The data were also used to investigate the possibility that internal waves generate the observed fine structure. On the basis of the temperature-salinity correlation of the fine structure and the extremely large required vertical displacements the vertical motions of internal waves can be ruled out as the primary cause of the fine structure. Because the Antarctic Polar Front Zone is a region of high horizontal temperature and salinity gradients and because there is an observed increase at one-half inertial period in drop-lagged coherences, it is hypothesized that the low-frequency nearly horizontal internal wave motions are generating the observed fine structure. However, in the particular case where direct observations of the vertical motions of internal waves are available, assuming that the relationship between vertical and horizontal displacements prescribed by the Garrett and Munk (1975) model holds, horizontal displacements are also ruled out as the sole source of the observed fine structure, yielding neither enough total variance nor the expected spectral shape; thus much of the observed variability may be attributed to temperature fine structure of noninternal wave origin.