Fracture Relative Permeability Research Articles

Steady-state relative permeability measurements in rough-walled fractures: The effects of wettability and aperture

Tight subsurface geosystems provide significant prospects for the recovery and storage of mass and energy. Because of the tightness of these systems, natural and engineered fractures are the main conveyance conduits transporting the fluids from the tight rock matrix to the wellbore or vice versa. During the fracturing process, most of the newly induced fractures are considered water-wet, however during injection/production, the wettability of the fractures gradually changes. These changes are mainly due to the interactions between the resident and injected fluids, or the exposure of the virgin fracture surfaces to the resident fluids during production. This alteration in wettability can affect the trapping and flow dynamics, e.g., relative permeability, of the fluids flowing in the fracture. Furthermore, fluid injection and production into and from these systems impact the fractures pore pressure and hence the effective stress they are exposed to, resulting in variations in the fracture aperture. In this study, we present a comprehensive macro-scale experimental investigation focusing on the impact of wettability and aperture on steady-state two-phase relative permeability in rough-walled fractures. Using the stead-state measurement technique, we meticulously characterized oil-brine relative permeabilities and residual trapping in water-wet, oil-wet, and mixed-wet rough-walled fractures induced in Eagle Ford shale rock samples. Additionally, we assessed the influence of fracture aperture size on these properties during both drainage and imbibition flow processes. Our results indicate significant phase interference in oil-brine flow in non-water-wet rough-walled fractures, which renders the commonly used x-curve and Corey models inadequate to represent the steady-state oil-brine relative permeabilities measured in our study, leading to substantial overestimations. Mixed-wet fractures exhibited reduced relative permeabilities compared to oil-wet fractures, which in turn demonstrated lower relative permeabilities than water-wet counterparts. The observed trends stem from evolving fluid configuration and transport dynamics within the fractures as surface wettability transitions. Furthermore, an increase in fracture aperture corresponded with an increase in relative permeability. This was attributed to a broader flow area, diminished capillarity, attenuated impact of fracture wall roughness and tortuosity effects, and a reduction in bypassing and trapping events, all synergistically contributing to the mitigation of phase interference. Similarly, an increase in fracture aperture led to a marked decrease in post-waterflooding endpoint oil saturation and post-oil flooding endpoint brine saturation. Finally, we provided generalized correlation models based on experimental results from fractures with varying conductivities and wettability, yielding a more accurate representation of fracture relative permeabilities compared to traditional models. The data and correlation models produced in this study improve our understanding and prediction of multiphase flow in subsurface fractures and offer insights into rapid production decline in unconventional shale reservoirs.

A hybrid model for the combined impact of non-Darcy flow, stimulated matrix permeability, and anomalous diffusion flow in the unconventional reservoirs

Abstract A hybrid model for unconventional gas reservoirs that couples three different parameters is presented in this paper. The first is the anomalous diffusion in a fractal porous media. The second is the stimulated or induced matrix permeability in the stimulated reservoir volume (SRV). The third is the non-Darcy flow permeability in the hydraulic fractures. This model is generated from the multi-linear flow model for fractal reservoirs controlled by diffusive flow mechanism with adjustment for fluid flux through hydraulic fracture face considering minimum fracture relative permeability (kmr) and non-Darcy flow Number (FND). Pressure distributions, flow regimes, and reservoir performances have been investigated for three types of unconventional reservoirs. The first is formations with homogenous matrix permeability where petrophysical properties of stimulated and un-stimulated reservoir volume are the same. The second is fractal reservoirs with different petrophysical properties in the two volumes without considering normal or classic diffusion mechanism. The third is the fractal reservoirs where anomalous diffusive flow mechanism dominates fluid flow. A set of comparisons has been generated between the three types for better understand the impact of non-Darcy flow permeability and stimulated matrix permeability on reservoir performance under normal and anomalous diffusion flow mechanisms. The outcomes of this study are: (1) Generating a new analytical model that describes pressure distribution in fractal unconventional reservoirs and couples non-Darcy flow, stimulated or induced matrix permeability with the anomalous diffusion in porous media. (2) Understanding the impact of these different parameters on reservoir performance. (3) Developing different models for all types of flow regimes that are expected to be observed during the entire production life. (4) Comparing the productivity index of reservoirs: having homogeneous matrix permeability, fractal with normal diffusion, and fractal with anomalous diffusion. The most interesting points in this study are: (1) Minimum fracture relative permeability (kmr) significantly enhances the productivity index by eliminating the impact of non-Darcy flow while non-Darcy flow number (FND) works conversely (2) Increasing stimulated matrix permeability enhances reservoir performance (3) The impact of non-Darcy flow permeability of hydraulic fractures is seen at early and intermediate production time where transient flow is dominant. (4) Two different trends are recognized for the impact of anomalous diffusion flow: the first is a positive impact on the transient flow period and the second is negative in the pseudo-steady state flow.

Tilting and Flexural Stresses in Basins Due to Glaciations—An Example from the Barents Sea

Many of the Earth’s sedimentary basins are affected by glaciations. Repeated glaciations over millions of years may have had a significant effect on the physical conditions in sedimentary basins and on basin structuring. This paper presents some of the major effects that ice sheets might have on sedimentary basins, and includes examples of quantifications of their significance. Among the most important effects are movements of the solid Earth caused by glacial loading and unloading, and the related flexural stresses. The driving factor of these movements is isostasy. Most of the production licenses on the Norwegian Continental Shelf are located inside the margin of the former Last Glacial Maximum (LGM) ice sheet. Isostatic modeling shows that sedimentary basins near the former ice margin can be tilted as much as 3 m/km which might significantly alter pathways of hydrocarbon migration. In an example from the SW Barents Sea we show that flexural stresses related to the isostatic uplift after LGM deglaciation can produce stress changes large enough to result in increased fracture-related permeability in the sedimentary basin, and lead to potential spillage of hydrocarbons out of potential reservoirs. The results demonstrate that future basin modeling should consider including the loading effect of glaciations when dealing with petroleum potential in former glaciated areas.

Viability of Gas-Injection EOR in Eagle Ford Shale Reservoirs

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 191673, “Dynamic Data Analysis With New Automated Work Flows for Enhanced Formation Evaluation,” by Safian Atan, SPE, Arashi Ajayi, Matt Honarpour, Edward Turek, SPE, Eric Dillenbeck, and Cheryl Mock, BHP, and Mahmood Ahmadi and Carlos Pereira, MI3 Petroleum Engineering, prepared for the 2018 SPE Annual Technical Conference and Exhibition, Dallas, 24–26 September. The paper has not been peer reviewed. Gas-injection huff ’n’ puff enhanced-oil-recovery (EOR) techniques have the potential to improve liquid hydrocarbon recovery in ultratight, unconventional reservoirs. This paper studies the technical and economic viability of this EOR technique in Eagle Ford shale reservoirs using natural gas injection, generally after some period of primary depletion, typically through long, hydraulically fractured horizontal-reach wells. Reservoir-Analysis Work Flow Model Description. A compositional, fine-scale, dual-porosity, dual-permeability, symmetry-element numerical model was used in this study to model the current primary depletion and the EOR huff ’n’ puff process. In this study, the element of symmetry, which represents the bottom half of a cluster within a fracturing stage, is being extended to include three wells to allow the investigation of the effect of interference and containment on pad-level cyclic-gas-injection deployment. Production and injection of the entire well come from all active stages in each well, with equal weighting. The production and the injection for each cluster in every well are calculated proportionally by use of these assumptions. Model Input. The complete paper describes the critical input for the numerical model, including fracture half-length and fracture height, shape factor, absolute and relative permeability, and pressure/volume/temperature (PVT). History-Matching Work Flow. Because the history-matching solution is known to be highly nonunique, a comprehensive probabilistic approach was used to identify the realistic solution space. To facilitate this process, the authors used a three-step approach: Identify the solution space through parametric study. Perform combinatorial analysis of predetermined variables and understand available solutions within the solution space. Fine-tune history matching to identify the correct combination of parameters for probable solutions. Characterizing the Performance of Cyclic Natural-Gas Injection The compositional fluid-flow analysis of the combined sample of the separator liquid and gas at reservoir conditions indicated a volatile oil in the reservoir. To evaluate the phase behavior of the mixture, the original oil and the gas supplied for injection purposes were mixed at different ratios. For each mixture, the calibrated equation of state (EOS) is used to evaluate the resulting phase diagram and fluid properties by modeling a constant-composition-expansion experiment at reservoir conditions. The 1979 Peng-Robinson EOS with nine components was used to model the PVT changes resulting from the composition changes related to each injection ratio. As the composition changes, the phase behavior and the fluid properties also change. The fluid system in the reservoir gradually changed from a volatile oil to a gas condensate. Results show that when injected-gas makeup is 20% or greater, the phase behavior changes from volatile oil to gas condensate. When the mixture consists of more than 70% injected gas, at any pressure below 6,000 psi, there is a possibility that condensation can occur.

An innovative approach to relative permeability estimation of naturally fractured carbonate rocks

This paper presents an innovative numerical procedure for flow simulation and estimation of relative permeability of naturally fractured carbonate rocks by history matching laboratory derived multi-phase production data. The multi-phase flow simulator accounts for flow in discrete fractures with variable asperities. These discrete fractures are characterised by the fracture surface topography which is imaged with the use of surface laser scanning and micro computed tomography (μ-CT). Next, the production data for naturally fractured carbonate samples (matrix and fracture permeability), samples with no fracture (matrix permeability only) and samples with fracture only (near zero matrix permeability) for unsteady state conditions are obtained. Forward simulation performed by coupling both the matrix and fracture relative permeability to estimate production for a porous fractured system. This is validated by comparing to the laboratory obtained production data. This has allowed us to validate the proposed numerical procedure and subsequently history match the experimental production data for the porous fractured system to obtain overall porous fractured relative permeability curves. Results of this study show that there exists a strong discontinuity of phase saturation. It was also observed that Corey's parameters are best suited for history matching of the production data through porous matrix, and cubic parameters are best suited for fracture.

Analytical Estimation of Water-Oil Relative Permeabilities through Fractures

Modeling multiphase flow through fractures is a key issue for understanding flow mechanism and performance prediction of fractured petroleum reservoirs, geothermal reservoirs, underground aquifers and carbon-dioxide sequestration. One of the most challenging subjects in modeling of fractured petroleum reservoirs is quantifying fluids competition for flow in fracture network (relative permeability curves). Unfortunately, there is no standard technique for experimental measurement of relative permeabilities through fractures and the existing methods are very expensive, time consuming and erroneous. Although, several formulations were presented to calculate fracture relative permeability curves in the form of linear and power functions of flowing fluids saturation, it is still unclear what form of relative permeability curves must be used for proper modeling of flow through fractures and consequently accurate reservoir simulation. Basically, the classic linear relative permeability (X-type) curves are used in almost all of reservoir simulators. In this work, basic fluid flow equations are combined to develop a new simple analytical model for water-oil two phase flow in a single fracture. The model gives rise to simple analytic formulations for fracture relative permeabilities. The model explicitly proves that water-oil relative permeabilities in fracture network are functions of fluids saturation, viscosity ratio, fluids density, inclination of fracture plane from horizon, pressure gradient along fracture and rock matrix wettability, however they were considered to be only functions of saturations in the classic X-type and power (Corey [35] and Honarpour et al. [28, 29]) models. Eventually, validity of the proposed formulations is checked against literature experimental data. The proposed fracture relative permeability functions have several advantages over the existing ones. Firstly, they are explicit functions of the parameters which are known for each of simulation computational cells or easy to measure in laboratory. It is also the first model that takes gravity effects and wettability of fracture walls into consideration and individually developed for water and oil-wet systems. Furthermore, the newly developed formulations are simple, efficient and accurate. Thus, they are recommended for implementation in dual and multiple continuum commercial reservoir simulators.

How fracture systems affect permeability development in shallow-water carbonate rocks: An example from the Gargano Peninsula, Italy

Fracture networks control the permeability of many reservoirs. Since the fracture patterns of petroleum reservoirs in situ are difficult to study in detail, field analogues are very important for understanding their fracture-related permeability. Here we present the results of a study of the fracture system of carbonate rocks of Lower Cretaceous age in a quarry associated with the damage zone and fault core of a major fault zone on the Gargano Peninsula in South Italy. We measured the attitude of 1541 fractures and faults along several vertical and horizontal scan lines. There are two main fracture sets: one strikes between E–W and ESE–WNW, the other NNE–SSW. A total of 675 fracture-spacing measurements indicate log-normal spacing distributions, with an arithmetic mean fracture spacing of 0.29 m and a median of 0.15 m. The data, plotted on a log–log plot, suggest three main spacing subpopulations, each of which follows approximately a power law with different fractal dimensions. Subpopulation 1, where the spacing ranges from 1 to 10 cm and the straight-line slope D (“fractal dimension”) is 0.20, represents fractures confined to laminated carbonate mudstones (multilayers) that form the microbial mat deposits of a peritidal cycle. Subpopulation 2, where the spacing ranges from 11 to 55 cm and D is 0.77, represents fractures confined to thicker layers, forming a part of a peritidal cycle, the contacts of which are marked by stylolites. Subpopulation 3, where the spacing ranges from 56 to 243 cm and D is 2.81, represents fractures that dissect comparatively thick units of an entire peritidal cycle. For the spacing, the minimum coefficient of variation, C v, defined as standard deviation divided by the mean, is 1.00 (essentially randomly spaced fractures) while its maximum C v is 1.62, suggesting that some fractures form clusters, some clusters being denser than others. The clusters, composed of fractures with varying attitudes and therefore commonly intersecting, are likely to contribute significantly to the overall permeability of the carbonate rock. Fracture-aperture (opening) data ( N = 324) also show a log-normal size distribution, with a mean opening of 1.01 cm and median of 0.29 cm. Log–log plots indicate that a part of this data groups into two subpopulations, I and II, each of which follows approximately a power law. The straight-line slope D (“the fractal dimension”) of subpopulation I is 0.46, whereas that of subpopulation II is 1.49. We present boundary-element models showing that laminated carbonate mudstones and their contacts modify the local stress fields so as to encourage fracture offset and, commonly, arrest. Our results also show that when a fluid-driven subpopulation 2 fracture approaches subpopulation 1 fractures, the induced tensile stresses may result in the opening up of many of the subpopulation 1 fractures directly above the tip of the subpopulation 2 fractures. If, in addition, the contacts between the multilayers are weak, they also tend to open up, thus generating a large interconnected cluster of vertical fractures and horizontal contacts. The results suggest that the tensile stresses induced by a comparatively large fluid-driven subpopulation 2 fracture may contribute to the formation of an interconnected cluster of subpopulation 1 fractures and associated contacts, thereby significantly increasing the permeability of the carbonate rock.

Overview: Well Stimulation (July 2006)

As I write this, my third and final opportunity to select technical papers for this feature, I find myself in Baku, Azerbaijan, the birthplace of our modern-day petroleum industry. This is an amazing place, where the history of our industry collides with the present. It is still possible to see some of the earliest commercial oil wells that were dug by hand and cased with wood; while just offshore, huge new development projects use some of the most modern technology available to the industry. Even with current prices for oil and gas, our industry struggles to supply the energy to support the dynamic economies of the world today. Achieving the goal of long-term, low-cost sources of hydrocarbons will require significant technology advances in the area of well stimulation. From the papers I have seen this year, it is apparent that these technological advances will affect many different portions of our industry, from old, mature fields, where significant reserves have previously been economically unattractive, to the new, major ultradeepwater projects that are being evaluated today. The challenge will be to increase productivity, and then to maintain that increased productivity throughout the life of the field to provide improved ultimate recovery. New and innovative stimulation technologies are emerging that will shake the foundations of some of our tried and proven methods. Still, in other cases, we see elegant enhancements to improve the performance of existing technologies. It appears that the future challenge will be for us to find more-cost-effective ways to improve well productivity. It appears that well stimulation will remain a dynamic part of our industry. I am hopeful that this industry will continue to be attractive to new, innovative, and challenging minds who will continue to shape the future of the petroleum industry. Well Stimulation additional reading available at the SPE eLibrary: www.spe.org SPE 98329 "Evaluation of Nonlinear Fracture Relative Permeabilities and Their Impact on Waterfrac Performance in Tight Gas Sands" by R.B. Sullivan, SPE, Anadarko Petroleum Corp., et al. SPE 98314 "A Breakthrough Fluid Technology in Stimulation of Sandstone Reservoirs" by F.E. Tuedor, SPE, Schlumberger, et al. SPE 97659 "Controlling Formation Fines at Their Sources To Maintain Well Productivity" by P.D. Nguyen, Halliburton, et al. SPE 97161 "Proppant Flowback Prevention—A New Technology for Low-BHST Applications" by D.E. Johnson, SPE, Hexion Specialty Chemicals Inc., et al.

Multiphase-flow properties of fractured porous media

Water–air imbibition and oil–water drainage displacements were conducted using a laboratory flow apparatus in fractured sandstone systems. During the experiments, porosity and saturation were measured along the core using a Computerized Tomography (CT) scanner. 3-D saturation images were reconstructed to observe matrix–fracture interactions. Differences in fluid saturations and relative permeabilities caused by changes of fracture width have also been analyzed. In the case of water–air imbibition, narrower fracture apertures showed more stable fronts and delayed water breakthrough compared to the wide fracture systems. However, the final water saturation was higher in wide fracture systems, thus showing that capillary pressure in the narrow fracture has more effect on fluid distribution in the matrix. During oil–water drainage, oil saturations were higher in the blocks near the thin fracture, again showing the effect of fracture capillary pressure. Oil fingering was observed in the wide fracture. Fine-grid simulations of the experiments using a commercial reservoir simulator were performed. Relative permeability and capillary pressure curves were obtained by history matching the experiments. The results showed that the assumption of fracture relative permeability equal to phase saturation is incorrect. It was found that both capillary and viscous forces affect the process. The matrix capillary pressure obtained by matching an experiment showed lower values than those reported in the literature.

The effect of CO2 on the geomechanical and permeability behaviour of brown coal: Implications for coal seam CO2 sequestration

Abstract Theory from fracture mechanics and thermodynamics coupled with the results of experimental studies provides evidence to suggest that the adsorption of carbon dioxide on coal causes a decrease in the coal strength. Coal weakening by the introduction of CO 2 to a coal seam may induce fracturing, causing a permeability increase under in situ conditions. Such effects present significant implications for proposals regarding the storage of CO 2 in coal seams. A uniaxial and triaxial laboratory study was carried out to explore the effects of the adsorption of CO 2 on the compressive strength and permeability of southeast Australian brown coal. Comparison of the stress–strain response of air-saturated and CO 2 -saturated specimens revealed a compressive strength decrease in the order of 13% and an elastic modulus decrease of about 26% for the uniaxial testing, but no significant strength or elastic modulus decrease for the triaxial testing. The absence of an adsorptive effect on the mechanical behaviour of the triaxial specimens may have been due to an insufficient saturation period under simulated ground conditions, or due to mechanical variability in the brown coal test specimens, however, further testing is required to reveal the reason for the apparent negligible strength reduction with CO 2 adsorption at the higher confinement. Carbon dioxide outflow measurements during the stress–strain process demonstrated an initial permeability decrease with pore closure, followed by a significant increase in specimen permeability with fracturing. Issues that require consideration in the application of these results to coal seam CO 2 sequestration include: whether the expected regional and localised in situ stresses are sufficient to initiate fracturing with adsorptive weakening; how coal properties (e.g. rank, moisture content) are likely to affect the geomechanical influence of CO 2 adsorption, and the expected magnitude of the proposed fracture related permeability increase.

A physically based approach for modeling multiphase fracture–matrix interaction in fractured porous media

A physically based numerical approach is presented for modeling fracture–matrix interaction, which is a key issue for fractured reservoir simulation. Commonly used mathematical models for dealing with such interactions employ a dual- or multiple-continuum concept, in which fractures and matrix are represented as overlapping, different, but interconnected continua, described by parallel sets of conservation equations. The conventional single-point upstream weighting scheme, in which the fracture relative permeability is used to represent the counterpart at the fracture–matrix interface, is the most common scheme by which to estimate flow mobility for fracture–matrix flow terms. However, such a scheme has a serious flaw, which may lead to unphysical solutions or significant numerical errors. To overcome the limitation of the conventional upstream weighting scheme, this paper presents a physically based modeling approach for estimating physically correct relative permeability in calculating multiphase flow between fractures and the matrix, using continuity of capillary pressure at the fracture–matrix interface. The proposed approach has been implemented into two multiphase reservoir simulators and verified using analytical solutions and laboratory experimental data. The new method is demonstrated to be accurate, numerically efficient, and easy to implement in dual- or multiple-continuum models.

The effects of dykes and faults on groundwater flow in an arid land: the Red Sea Hills, Sudan

In this study the focus is on a part of the Red Sea Hills of Sudan, an area which suffers from a severe shortage of groundwater. This shortage is partly because the precipitation in this area is very small, from a maximum of only 164 mm year −1 to a minimum of 36 mm year −1. Partly, however, the shortage is related to the generally low permeability of the (mostly Precambrian but partly Phanerozoic) bedrock. The bedrock is, however, dissected by numerous lineaments, mostly faults and basaltic dykes, some of which transport groundwater to the surface in springs and wells. We made field studies of 107 dykes, complemented by Landsat ETM and SPOT image studies of 1419 lineaments interpreted as dykes. Additionally, we made image studies of 1707 lineaments interpreted as faults, fractures and shear zones many of which meet with the dykes at nearly right angles. Many of the dykes are of dense, low-permeability basalt and range in thickness up to 14 m and in length up to several kilometres. The dominant dyke strike is NNW, roughly parallel with the coast of the Red Sea and perpendicular to the topographic slope and the trends of many of the lineaments interpreted as faults. Using the field and image data, as well as a new digital elevation model of the study area, we propose a conceptual model to explain the relationship between faults, dykes and groundwater in the area. In this model the NNW-trending dykes, particularly the long and thick low-permeability dykes, act as barriers for much of the topography-driven groundwater flow. The groundwater collected by these dykes is transported along their margins towards the topographic depressions occupied by the (comparatively) high-permeability E–W trending fault zones. Because these fault zones trend parallel with the inferred hydraulic gradient in the area the faults also tend to collect groundwater. In terms of the model groundwater is thus driven along both dykes and faults to their near-orthogonal intersections. These intersections normally have relatively high fracture-related permeability, along which groundwater is transported towards the surface. This model thus predicts that water wells and springs would be expected at dyke–fault intersections, which is in agreement with the available data indicating that the majority of the springs occur at such intersections.

Estimation of fracture relative permeabilities from unsteady state corefloods

A methodology to test the possible deviations of fracture relative permeabilities from straight-line relationship with saturation is discussed. It is shown that with matrix relative permeability data known, it is possible to obtain fracture relative permeabilities by history matching experimental data with double porosity numerical models output. Rather than linear saturation dependence, fracture relative permeability is a power law function of the corresponding phase saturation. The impact of several important parameters like double porosity formulation, capillary pressure and shape factor is discussed. It has been found that double porosity formulations (other than the double permeability model) could represent the flow in a fractured medium.

Computation of Gas-liquid Drainage In Fractured Porous Media Recognizing Fracture Liquid Flow

Abstract We propose a simple approach to simulate gas-oil gravity drainage process in fractured porous media by using an appropriate fracture capillary pressure curve and an expression for effective fracture liquid permeability. The effective fracture liquid permeability is approximated by fracture permeability perpendicular to fracture planes. There is no need to provide fracture relative permeabilities in our model Numerical simulation results are in excellent agreement with experimental data. Introduction Gravity drainage in fractured porous media is related to:matrix permeability. relative permeability and capillary pressure:matrix block height and fluid density; andfracture two phase gas-oil flow characteristics. Immiscible gas-oil flow in homogeneous matrix porous media is a resolved issue. Fracture two-phase gas-oil flow is, however, complicated. The fracture permeability from the Poiseuille law (k = 83.3 × 105 (2/)2, k in µm2 / in cm) is for flow parallel to fracture planes, and it may not apply lo flow perpendicular to fracture planes. Fracture relative permeability is also unknown. There is no reason to believe that a straight line relative permeability would apply to gas liquid flow across fractures. Limited measurements by McDonald et al and Pruess et al2reveal that fracture relative permeability may have a shape similar to matrix permeability. These measurement are, however for flow parallel to fracture planes. In a recent study(3). we have investigated liquid flow across a single liquid bridge between two matrix blocks. An expression for the effective liquid permeability perpendicular to the fracture planes was derived. As we will discuss later in this paper, the proposed expression may provide effective fracture liquid permeability for the gas-oil flow across a fracture. It could replace the need for both the Fracture absolute permeability and [he relative permeabilily in the direction perpendicular to fracture plane. In Reference (3), as well as in this study. one witnesses a substantial pressure drop across a liquid bridge (Figure I) in a fracture. Capillary pressure at the inflow end of a liquid bridge could be as much as 3 kPa lower than capillary pressure at the outflow end. In other words capillary pressure at the base of an upper matrix block could be 3 kPa lower than capillary pressure at the top face of the matrix block underneath. The large liquid pressure drop across a fracture provides the driving force for liquid flow from one matrix block to the nei1!hbouring block. Since the effect of gravity force across a fracture with an aperture of say 10 to 100 microns is negligible the flow across; both horizontal and vertical fractures requires the same pressure drop. In a recent study(4), we have noted that capillary continuity realizes across fractures as thick as 1.000 microns. The same study has also revealed that the Young-Laplace equation of capillarity may underestimate fracture capillary pressure. In another study(5), we demonstrated that a combination of fracture capillary pressure derived from the Young-Laplace equation and various expressions for fracture relative permeability may not fully describe gas-oil gravity drainage in Fractured porous media.

Quantitative visualization of entrapped phase dissolution within a horizontal flowing fracture

An experiment was conducted to demonstrate the utility of quantitative fracture flow visualization techniques in the study of entrapped fluid phase (air) dissolution into a flowing phase (water) within a horizontal, transparent, analog rough‐walled fracture. The fracture aperture field and phase occupancy were measured using light transmission techniques and then combined to calculate bulk water‐phase saturation within the fracture as a function of time. Fracture relative permeability as a function of water‐phase saturation showed a smooth power law behavior during dissolution. Periodic step pulses of clear water within the dyed water inflow yielded dye concentration fields that demonstrate channeling induced by the entrapped air phase. Clusters of the entrapped air‐phase exhibited three types of dissolution behavior: general shrinkage, interfacial recession along cluster appendages, and cluster splitting. Locations for the advance of the wetting phase (water) into a nonwetting entrapped air cluster on its dissolution are not always correlated with either zones of high mass transfer rate (as inferred from gradients in the pulsed dye concentration fields) or with narrow apertures where the wetting phase has been thought to most easily invade. These results suggest that within an individual cluster of the entrapped phase, fluid pressure is at equilibrium and that the path of cluster shrinkage may be controlled primarily by capillary forces resulting from the full three‐dimensional curvature that minimizes surface energy of the phase interface.

Two‐Phase Flow Visualization and Relative Permeability Measurement in Natural Rough‐Walled Rock Fractures

A laboratory flow apparatus was used to visualize and measure two‐phase gas‐liquid flows in natural rough‐walled rock fractures. Experiments at carefully controlled flow rate and pressure conditions have been performed using a natural fracture and three transparent fracture replicas. Two‐phase flow exhibited persistent instabilities with cyclic pressure and flow rate variations even under conditions of constant applied boundary conditions. Visual observations of changes in pore occupancy showed that the instabilities could be explained as resulting from an interplay between capillary effects and pressure drop due to viscous flow. Measurements of relative permeabilities indicated strong phase interference, with relative permeabilities reduced to very small values at intermediate saturations for both wetting and nonwetting phases. These results run counter to a conventional view of fracture relative permeabilities that assumes that the relative permeability of each phase is equal to its saturation, but the results are consistent with recent models that view fractures as two‐dimensional heterogeneous porous media.

Oxygen and hydrogen isotopes in deep thermal waters from the south meager creek geothermal area, british columbia, canada

Deuterium and oxygen-18 ( 18O) have been measured in deep thermal, shallow thermal and non-thermal water samples collected at various times between 1982 and 1989 from the Meager Creek area, with the aim of assessing the origin of the thermal waters. The isotopic composition of the reservoir waters ( δ 18 O = −13‰ and δ D = −114.8‰ ) was calculated from data on post-flash deep thermal waters, using a two-stage steam loss model. The reservoir composition shows an oxygen shift of 2.4‰ relative to the local meteoric water line. The composition of the recharge, obtained by removing the oxygen shift, is isotopically heavier than the average local meteoric waters, suggesting that the recharge may be from an area to the west of Mt Meager where isotopically heavier ground-waters are likely to be found. The small δ 18O shift of the deep high-temperature waters is indicative of dominance of fracture-related permeability in the reservoir. Analysis of the chemistry and the temperature of the waters from hot springs and shallow thermal wells suggests that these waters have evolved from the deep geothermal waters through dilution by meteoric waters and about 40°C adiabatic cooling (steam loss).

The evolution of fracture-related permeability within the Ruby Star Granodiorite, Sierrita porphyry copper deposit, Pima County, Arizona

Quantitative data from the margins of the Sierrita porphyry copper deposit were derived by direct measurements of fractures in the field and fluid temperatures in the laboratory. These data constrain interpretations of the nature and extent of fracture permeability at different stages of cooling of the quartz monzonite porphyry which invaded the Ruby Star Granodiorite.Fracturing coeval with formation of the orebody extends into the granodiorite some 4.5 km from the center of the hydrothermal system. Integrated fracture densities decrease from values of 0.2 to 0.3 cm (super -1) near the system9s center to a background value of 0.03 cm (super -1) or less outside of the system. Four mineralogically different vein types with a distinct paragenetic sequence are present. Early veins, characterized by a quartz-orthoclase assemblage, are crosscut by two distinct types of sulfide-bearing quartz veins. The bulk of the copper mineralization is associated with the later of these two events. The final vein set present consists of an orthoclase-epidote assemblage. Distribution of the vein types in the granodiorite indicates that the areal extent of fracturing associated with each type diminishes with time.Vein filling temperatures determined from fluid inclusions at two localities reveal a general decrease in the temperature of deposition of vein quartz in each vein type as the system evolved. Homogenization temperatures in excess of 350 degrees C were observed in the quartz-orthoclase vein set. Temperatures in the quartz-sulfide vein assemblages were considerably lower, never exceeding 320 degrees C, and those in the final orthoclase-epidote vein set were lower still, never exceeding 260 degrees C. Sulfide-bearing quartz veins collected at sites 1.8 and 2.9 km from the system9s center showed similar temperatures of formation; however, secondary inclusions representing later events, present at the 1.8-km site, were absent at the 2.9-km site, suggesting that the late, lower temperature event related to their formation was less widespread.