Low-permeability Rocks Research Articles

Fault zone processes and fluid history in Austin Chalk, southwest Texas

Faults are commonly the largest fractures in a fracture network, forming the backbone of the permeability system in low-permeability rocks. Faults in outcrops of the Austin Chalk — an important oil and gas reservoir in south Texas, Louisiana, and westernmost Mississippi — exemplify deformation and fluid histories of subseismic-scale faults in mechanically layered chalk-dominated strata. Exposures of near-horizontal Austin Chalk in southwest Texas contain northwest- and southeast-dipping normal faults with exposed heights of meters to tens of meters and displacements of centimeters to decimeters. Local fault dips are steep to vertical through chalk and limestone beds and moderate through marl, mud rock, and clay-rich ash beds, producing refracted fault profiles. Failure surface characteristics indicate various failure modes, including tensile, hybrid, shear, and (locally) compactive shear behavior depending on the host lithology. Dilational zones associated with steep fault segments host calcite veins. Crack–seal textures in fault zone veins record repeated reactivation of refracted fault profiles. Fluid inclusion and stable isotope geochemistry analyses of fault veins indicate formation at depths of 1.4 to 2.9 km (4593 to 9514 ft) and possibly of 4.2 km (13,780 ft). Fluids include locally sourced saline waters and externally sourced waters and oil in rocks that did not reach oil maturation conditions. Inclusions of 30° API to greater than 50° API oil are found in veins 30 km (19 mi) updip from the Eagle Ford Formation oil zone. These results illustrate the migration of oil and other fluids within subseismic-scale Austin Chalk faults and fundamental control of lithology on fault zone architecture.

Characterisation of Surat Basin Walloon interburden and overlying Springbok Sandstone: a focus on methane adsorption isotherms, permeability and gas content

The Surat Basin in Queensland is one of the world’s premier producers of natural gas from coal seams. We investigate the potential for clay-rich Walloon Coal interburden and the overlying Springbok Sandstone to hold or produce gas. Seventeen core samples were analysed from two wells from intervals within the Walloon Upper Juandah Coal Measures interburden and the Springbok Sandstone. Samples were characterised using high-pressure methane adsorption isotherms, canister gas desorption tests, moisture contents, ash contents, carbon contents, scanning electron microscopy/energy dispersive X-ray spectrometry, X-ray quantitative clay analysis, permeability, helium pycnometry and mercury intrusion porosimetry. Methane adsorption was conducted at 30°C with up to 8 MPa pressure on dried crushed samples. The adsorption capacity of methane at 8 MPa varied from 3 cc/g (calcite-cemented) up to 25 cc/g (standard temperature and pressure equivalent) (coal). Clay-rich interburden samples adsorbed ~5–14 cc/g (dry). The measured isotherms and methane content from canister desorption tests show that appreciable volumes of gas are contained within some portions of interburden and in the overlying Springbok Sandstone. Gas within the interburden likely represents a large volumetric resource, albeit in low permeability rock that restricts direct productivity. The gas adsorption and gas content results for the Springbok Sandstone help to explain field observations of high gas content in some landholder water wells.

Methane Isotherms and Magnetic Resonance Imaging in Shales

Adsorption isotherms of light hydrocarbons on reservoir rocks are key data used to quantify the total gas content in reservoirs and isotherms are now being used to improve our understanding of the processes affecting subsurface gas flow associated with gas injection from Enhanced Oil Recovery techniques. This project combined elements of the traditional pressure-volume gas adsorption isotherm technique and an NMR-based adsorption isotherm approach to determine the adsorption isotherms of light hydrocarbons on to tight rocks from oil and gas reservoirs. The new approach allows isotherms to be derived from NMR data. First, a T2distribution of the gas is determined over a range of gas pressures. Next, the volume of pore gas is estimated using the pore volume of the rock and the Van der Waals gas equation. The adsorbed gas content is then calculated by subtracting pore gas content from the total gas content. This is repeated for a range of gas pressures to determine the adsorption isotherm. This project used the NMR method described above and measured the gas pressure decay in the NMR cell. This combined approach includes the advantages of the NMR method but it also produces a pressure-time curve that can be used to identify when equilibrium is attained in low permeability rocks and can be used to compare adsorption kinetics of different gases. The advantages of our approach are that 1) the samples remain intact and the measurements provide information on the pore size distribution; 2) analyses can be carried out at reservoir pressures; 3) isotherms can be measured for any gas containing hydrogen atoms; and 4) the results can be used to examine the processes controlling gas flow through the rock. Future work to develop this technique will improve our quantification of the amount of pore gas in the cell, which will improve our partitioning between adsorbed gas and pore gas as well as allow for an improved analysis of the pressure response of the sample after degassing.

Нелинейность законов фильтрации в низкопроницаемых коллекторах

Filtration processes in low-permeability oil and gas reservoirs are characterized by non-linearity of filtration laws, which determines the features of mathematical modeling of these processes. Based on the concept of the formation of adsorption-solvate layers of a filtering liquid near the pore surface, which narrow the effective flow section of the pore channels, nonlinear dependences of the filtration rate on the applied pressure gradient are obtained. The obtained dependencies are in good agreement with the available experimental data and can be recommended for use in mathematical modeling of filtration processes in low-permeability rocks.

Towards Relative Permeability Measurements in Tight Gas Formations

Relative permeability is a concept used to convey the reduction in flow capability due to the presence of multiple fluids. Relative permeability governs the multiphase flow, therefore it has a significant importance in understanding the reservoir behavior. These parameters are routinely measured on conventional rocks, however their measurement becomes quite challenging for low permeability rocks such as tight gas formations. This study demonstrates a methodology for relative permeability measurements on tight gas samples. The gas permeability has been measured by the Step Decay method and two different techniques have been used to vary the saturations: steady state flooding and vapor desorption. Series of steady-state gas/water simultaneous injection have been performed on a tight gas sample. After stabilization at each injection ratio, NMR T2, NMR Saturation profile and low pressure Step Decay gas permeability have been measured. In parallel, progressive desaturation by vapor desorption technique has been performed on twin plugs. After stabilization at each relative humidity level the NMR T2 and Step Decay gas permeability have been measured in order to compare and validate the two approaches. The techniques were used to gain insight into the tight gas two phase relative permeability of extremely low petrophysical properties (K<100 nD, phi < 5 pu) of tight gas samples of Pyrophyllite outcrop. The two methods show quite good agreement. Both methods demonstrate significant permeability degradation at water saturation higher than irreducible. NMR T2 measurements for both methods indicates bimodal T2-distributions, and desaturation first occurs on low T2 signal (small pores). Comparison of humidity drying and steady-state desaturation technique has shown a 12-18 su difference between critical water saturation (Swc) measured in gas/water steady-state injection and irreducible saturation (Swirr) measured by vapor desorption.

Effect of fracture orientation on ultrasonic wave signatures

Fluid flow through low-permeable rock masses is dominated by transport through discontinuities such as fractures, faults, and joints present in the rock. These discontinuities are beneficial for some geo-resources such as geothermal, oil and gas reservoir, but detrimental for other applications such as CO2 storage and hazardous waste isolation. Fracture orientation plays a critical role during the design of the geo-resources. Often times, ultrasonic waves are used in the field to locate and characterize the fractures. In this study, the effect of fracture orientation (0° to 90°) on ultrasonic wave signatures was investigated by conducting a series of experiments on a granite rock with a longitudinal fracture under confining pressures of 15, 30, and 45 MPa. Ultrasonic wave signatures during the experiment were collected using the ultrasonic transducers embedded in the core holders that were attached to the two ends of the specimen. Results indicated sensitivity of the ultrasonic wave velocities, waveforms, and amplitudes (cross-polarized S-waves) to the fracture orientation.

Mechanical stratigraphy and structural control of oil accumulations in fractured carbonates of the Irati Formation, Paraná Basin, Brazil

Abstract Fracturing analysis of low-permeability rocks as reservoir analogs have increased in recent years. The main mechanism involved in the development of secondary porosity in low-permeability, fine-grained limestones of the Irati Formation is fracturing. In these rocks, oil accumulates along fracture planes, vuggy porosity, microfractures, breccias, as well as bedding discontinuities. Joints represent the central element for oil migration and the connection between accumulation sites. Joints are unevenly distributed across the succession of rock types, where carbonate rocks have a much denser array of joints than shales and siltstones. From a mechanical stratigraphy point of view, limestones have a brittle behavior and constitute mechanical units. Ductile shale and siltstone are mechanical interfaces capable of blocking joint propagation. Joints running NW-SE are more effective in trespassing the mechanical interface and are, therefore, more persistent. Joints running NE-SW are less persistent because the ductile behavior of the first two shale beds above the limestone blocks their propagation. The spatial arrangement of regional NW-SE and NE-SW joints promoted reservoir connection, allowing oil migration and accumulation. The joints and oil migration (at least three phases) developed as a consequence of the Gondwana Breakup and are also associated with local pressure gradients.

Hydraulic stimulation and fluid circulation experiments in underground laboratories: Stepping up the scale towards engineered geothermal systems

The history of reservoir stimulation to extract geothermal energy from low permeability rock (i.e. so-called petrothermal or engineered geothermal systems, EGS) highlights the difficulty of creating fluid pathways between boreholes, while keeping induced seismicity at an acceptable level. The worldwide research community sees great value in addressing many of the unresolved problems in down-scaled in-situ hydraulic stimulation experiments. Here, we present the rationale, concepts and initial results of stimulation experiments in two underground laboratories in the crystalline rocks of the Swiss Alps. A first experiment series at the 10 m scale was completed in 2017 at the Grimsel Test Site, GTS. Observations of permeability enhancement and induced seismicity show great variability between stimulation experiments in a small rock mass body. Monitoring data give detailed insights into the complexity of fault stimulation induced by highly heterogeneous pressure propagation, the formation of new fractures and stress redistribution. Future experiments at the Bedretto Underground Laboratory for Geoenergies, BULG, are planned to be at the 100 m scale, closer to conditions of actual EGS projects, and a step closer towards combining fundamental process-oriented research with testing techniques proposed by industry partners. Thus, effective and safe hydraulic stimulation approaches can be developed and tested, which should ultimately lead to an improved acceptance of EGS.

Effective Mechanisms to Relate Initial Rock Permeability to Outcome of Relative Permeability Modification

Excessive water production is becoming common in many gas reservoirs. Polymers have been used as relative permeability modifiers (RPM) to selectively reduce water production with minimum effect on the hydrocarbon phase. This manuscript reports the results of an experimental study where we examined the effect of initial rock permeability on the outcome of an RPM treatment for a gas/water system. The results show that in high-permeability rocks, the treatment may have no significant effect on either the water and gas relative permeabilities. In a moderate-permeability case, the treatment was found to reduce water relative permeability significantly but improve gas relative permeability, while in low-permeability rocks, it resulted in greater reduction in gas relative permeability than that of water. This research reveals that, in an RPM treatment, more important than thickness of the adsorbed polymer layer ( e ) is the ratio of this thickness on rock pore radius ( e r ).

Faults controlling geothermal fluid flow in low permeability rock volumes: An example from the exhumed geothermal system of eastern Elba Island (northern Tyrrhenian Sea, Italy)

Geothermal fluid circulation and storage within rock volumes are essential conditions for an effective geothermal system. Although several studies examine fluid migration through permeable rock volumes, few papers deal with fluid flow and fluid-rock interaction within the cap rocks of magma-driven geothermal systems. In this paper, I present the results of an integrated study focused on the circulation of geothermal fluids and fluid-rock interaction with clayey-carbonate sedimentary rocks and interbedded tectonic slices of serpentinite, representing the cap of an exhumed geothermal system located in the south-eastern Elba Island (Acquarilli-Norsi area, Tuscan Archipelago).Structural and kinematic data highlight that the prevalent geothermal fluid pathways correspond to NE-trending normal to oblique-slip faults. A Fe-amphibole + quartz + calcite ± chlorite ± epidote ± titanite mineral assemblage filled the fracture networks associated with two different fault generations. Fluid-rock interaction gave rise to skarnoids having three distinct mineralised zones, locally, crossed by the faults.Fluid inclusions data on quartz and calcite coexisting with the amphibole in the first fault generation and calcite of the second fault generation suggest that at least two paleo-geothermal fluids permeated through the fault zones, at a maximum P of about 0.8 kbar. The sequence was (i) first an H2O-rich fluid enriched by a volatile phase mainly made up of CO2 derived from the decarbonation and dehydration reactions of the hosting metacarbonate and metapelitic rocks. This fluid characterised by temperature up to 495 °C and salinity between 1.0 and 6.4 wt.% NaClequiv, records the residual intra-formational fluid (derived from dehydration of phyllosilicate and serpentinite bodies) already present within the host rocks. This fluid was successively mobilised during the development of the fault zones and progressively cooled and CO2-depleted with time; (ii) a second fluid likely of meteoric origin, devoid of CO2 and characterised by relatively low-temperature from 146.5 to 254 °C and salinity between 1.9 and 2.9 wt.% NaClequiv related to the last fluid circulation event. The main conclusions are that: (i) geothermal fluid circulation occurred within the cap rocks of the paleo-geothermal system, along fault zones; (ii) fluid circulation occurred within restricted fault-damaged volumes, developed in an extensional setting; iii) faults dissected rocks that were affected by high-temperature metamorphism induced by the cooling of a magmatic intrusion. The super-hot fluid was produced by metamorphic reactions and only in the latest stage, meteoric water infiltrated in the geothermal system due to the progressive faulting and exhumation.

An Environment Friendly Approach to Reduce the Breakdown Pressure of High Strength Unconventional Rocks by Cyclic Hydraulic Fracturing

Abstract Unconventional hydrocarbon resources mostly found in highly stressed, overpressured, and deep formations, where the rock strength and integrity are very high. When fracturing these kinds of rocks, the hydraulic fracturing operation becomes much more challenging and difficult and in some cases reaches to the maximum pumping capacity limits without generating any fracture. This reduces the operational gap to optimally place the hydraulic fractures. Current stimulation methods to reduce the fracture pressures involvement with adverse environmental effects and high costs due to the entailment of water mixed with huge volumes of chemicals. In this study, a new environment friendly approach to reduce the breakdown pressure of the unconventional rock is presented. The new method incorporates the injection of chemical-free fracturing fluid in a series of cycles with a progressive increase of the pressurization rate in each cycle. This study is carried out on different cement blocks with varying petrophysical and mechanical properties to simulate real rock types. The results showed that the new method of cyclic fracturing can reduce the breakdown pressure to 24.6% in ultra-tight rocks, 19% in tight rocks, and 14.8% in medium- to low-permeability rocks. This reduction in breakdown pressure helped to overcome the operational challenges in the field and makes the fracturing operation much greener.

Distinct deep subsurface microbial communities in two sandstone units separated by a mudstone layer

Deep subsurface microbial communities are more abundant in coarse-grained sedimentary rocks such as sandstones than in fine-grained mudstones. The low porosity and low permeability of mudstones are believed to restrict microbial life. Then, it is expected that distinct, isolated microbial communities may form in sandstones separated by mudstones. In this context, the connectivity between microbial communities in different sandstone units can be investigated to infer evolutionary patterns of diversification in space-time, which may potentially contribute with relevant data for analyses of hydraulic connectivity and stratigraphic correlation. In this work, we used high throughput DNA sequencing of a ribosomal 16S gene fragment to characterize the prokaryotic communities found in Permian sandstone samples of the same core that are separated by one mudstone interval, in the Charqueadas coal field, Parana Basin (Southern Brazil). Our samples were collected at ∼300 m deep, in porous sandstones separated by a thick mudstone package. Differences in the bacterial community structure between samples were observed for the classified OTUs, from phylum to genus. Molecular biology might be further applied as a possible tool to help to understand the spatial and temporal distribution of depositional facies, and the efficiency of low permeability rocks to compartmentalize reservoirs. Ongoing studies aim to extend the present investigation into further analyses regarding lateral changes in microbial communities present in the same sandstone units.

Experimental investigation of oil generation, retention, and expulsion within Type II kerogen-dominated marine shales: Insights from gold-tube nonhydrous pyrolysis of Barnett and Woodford Shales using miniature core plugs

Although oil retention has recently emerged as a key topic of unconventional-shale resource assessment, oil-retention and expulsion controls in organic-rich shales during thermal maturation remain poorly constrained. This study presents an experimental comparison of oil generation, retention, and expulsion in two immature, Type II kerogen-dominated marine shales, the Mississippian Barnett Shale and the Upper Devonian-Lower Mississippian Woodford Shale, mainly with respect to the combined effects of the organic macerals and rock fabric involved. In both cases, miniature core plugs drilled from the given samples were isothermally pyrolyzed at 130 to 425 °C for 72 h under a confining pressure of 68 MPa during gold-tube nonhydrous pyrolysis, corresponding to the thermally immature, early stage of the oil window, the main stage of the oil window, the late stage of the oil window, the main stage of oil cracking to wet gas, and the late stage of oil cracking. Yields of generated oil, retained oil, and expelled oil for the two studied samples were systematically quantified on the basis of mass-balance calculation of measured oil and gas yields, as well as Rock-Eval analyses on pyrolyzed subsamples.Through the six stages of petroleum formation investigated, the principal difference in oil generation was observed in the two studied samples, with approximately 38 to 68% greater yields of generated oil (equivalent to ~130 mg oil/g TOCo) for the Woodford Shale when it evolved into the main and late stages of the oil window. These elevated yields of generated oil for the Woodford Shale were compensated for by additional oil generation resulting from conversion of abundant Type I kerogen-like algae such as Tasmanites and Leiosphaeridia, which lag in onset and have a shorter period of petroleum generation upon maturation. As a response to the difference in oil generation, oil retention was found to be significantly enhanced for the Woodford Shale at equivalent stages, with 0.2 to 1.7 times more free oil (equivalent to 24–105 mg oil/g TOCo) and 0.7 to 3.9 times more sorbed oil (equivalent to 58–76 mg oil/g TOCo) being retained than that of the Barnett Shale, although this effect was not pronounced for oil expulsion. In contrast to the Barnett Shale, relatively low expelled oil yields and expulsion efficiencies both indicate highly limited oil expulsion in the Woodford Shale, implying that the Woodford Shale, whose mineral composition and lithofacies are similar to those of the Barnett Shale, may have a relatively low permeability rock fabric to prevent oil from being expelled. Furthermore, not only significantly higher oil-saturation index (OSI) values but also a wider range of maturity at which the oil crossover effect (OSI > 100 mg/g TOC) occurs is expected for the Woodford Shale when extrapolation to a geological setting occurs. These data suggest that the presence of abundant Type I kerogen-like algae and relatively low permeability rock fabric in the Woodford Shale are critical to significant oil retention during oil generation and expulsion, which jointly raise the possibility of potential commercial shale oil within Type II kerogen-dominated marine shales.

Comparative study of Basel EGS reservoir faults inferred from analysis of microseismic cluster datasets with fracture zones obtained from well log analysis

Petrothermal systems seek to extract energy from hot, low-permeability rocks that in northern Switzerland lie at 4–6 km depth. Permeability is enhanced by performing large ‘hydraulic stimulation’ injections, such as occurred in the 5 km deep well at Basel, Switzerland. Knowledge of the discontinuity properties and distribution in target reservoirs can help design such stimulations, but characterisation is challenging because of limited rock mass exposure. Rock mass fractures below Basel were investigated in previous studies by analyses of acoustic televiewer data of the Basel-1 well and by fault plane solutions. In addition, seismic events with high similarity of seismic waveforms were grouped into clusters and interpreted to have originated from slip of patches of a common fault or fault zone. In this study we investigate the orientations of fault patches from seismic clusters, considering relative location errors of cluster events with Monte-Carlo simulations, and use common events in clusters ranging in size from few 10s to many 100s of metres to explore the internal architecture of larger fault zones at Basel. We find that the orientations of microseismically-inferred faults and borehole fractures are similar and that fracture zones consist of sub-parallel or ‘anastomosing’ fractures.

Estimating the seepage effect of SC-CO2 and water fracturing with a steady-state flow model considering capillary and viscous forces at the pore scale

Supercritical carbon dioxide (SC-CO2) fracturing is a promising technology for unconventional energy development and carbon capture and storage. Experimental studies have shown that SC-CO2 fracturing can form complex fracture networks and reduce crack initiation pressure, which are different results from those when fracturing with aqueous fluids. The complex fracture networks that form from SC-CO2 fracturing may be the result of strong seepage effects (i.e., low capillary and viscous forces). To understand the different injection behaviors induced by SC-CO2 and aqueous fluids in low-permeability rocks, this study develops a new two-phase steady-state model based on the pore-scale network method. Although other models consider the viscous force, our model implements the capillary and viscous forces to reproduce the seepage effect. Because of the capillary force, the flow model is nonlinear and solved by iteratively solving matrix equations until a conservation of volumetric flux is satisfied. Simulation results show that the capillary force in a two-phase flow system in small pore spaces has consequential effects on its pressure distribution. Such factors lead to discontinuous pressure drops. This study shows that the seepage effect of SC-CO2 is stronger than that of aqueous fluids and can largely avoid the capillary blockage that arises in oil-water systems.

Study of the thermal influence on the displacement of high-viscous oil by reservoir water from the Bashkirian core of Akansky field

The article discusses the results of physical laboratory modeling of nonisothermal oil displacement by formation water on model composite core samples of the Akansky field, performed on a VINCI CFS-700 filtration unit. In the work, the influence of the permeability of composite core samples on the results of nonisothermal oil displacement by formation water was studied. An analysis of the performed experiments shows that the influence of the temperature regime on the displacement coefficient manifests itself to varying degrees on samples of different permeabilities. The change in the displacement coefficient at various temperature conditions occurs most strongly in low-permeability rock samples, in high-permeability rocks the changes are less significant. Use for displacing produced water with a temperature below the initial formation water (within 2-5ºС) provokes a greater decrease in the displacement coefficient than the use of slightly heated water (within 7ºС). The presence of highly differentiated rock samples by permeability revealed when drilling productive formations significantly complicates the processes of oil displacement. The local highly permeable sections available in the context of productive formations can act as intensifying the process of displacing the zone with the right choice of temperature and exposure technology.

A social take on unconventional resources: Materiality, alienation and the making of shale gas in Poland and the United Kingdom

Unlike conventional resources, unconventional gas (such as shale gas) is trapped in low permeability rock, from which it does not flow naturally. Hence, its extraction is costly and requires sophisticated technologies. Building on my ethnographic work in north-west England and south-east Poland, I explore people’s engagements with shale gas materialities to show how the category of an ‘unconventional resource’ – framed by geological and engineering sciences – has more than merely technological implications. Instead, shale gas produces new sociotechnical relations by trying to remove itself from social entanglements. These attempts fail to contain the unruly forces of the subsurface and local impacts, bringing the alienating dynamics of resource-making into sharp relief. The irregularities of materials and infrastructural limits, integral to the socially dis-embedded ‘unconventionality’ of the developments, inadvertently turn shale gas projects into a site of the political.

Simulation of the interactions between hydraulic and natural fractures using a fracture mechanics approach

Abstract HYDROCK method aims to store thermal energy in the rock mass using hydraulically propagated fracture planes. The hydraulic fractures can interact with the pre-existing natural fractures resulting in a complex fracture network, which can influence the storage performance. This study investigates the interactions between hydraulic and natural fractures using a fracture mechanics approach. The new functionality of the fracture mechanics modelling code FRACOD that enables crossing of hydraulically driven fracture by a pre-existing fracture is presented. A series of two-dimensional numerical models is prepared to simulate the interaction at different approach angles in granitic rock of low permeability. It is demonstrated that multiple interaction mechanisms can be simulated using the fracture mechanics approach. The numerical results are in agreement with the modified Renshaw and Pollard analytical criterion for fracture crossing. The results show that for large approach angles, the hydraulic fracture crosses the natural fracture, whereas for small approach angles, the hydraulic fracture activates the natural fracture and the wing-shaped tensile fractures are propagated from its tips. Thus, the presence of fractures with low dip angles can lead to the growth of more complex fracture network that could impair the thermal performance of the HYDROCK method.

Pore-scale study of counter-current imbibition in strongly water-wet fractured porous media using lattice Boltzmann method

Oil recovery from naturally fractured reservoirs with low permeability rock remains a challenge. To provide a better understanding of spontaneous imbibition, a key oil recovery mechanism in the fractured reservoir rocks, a pore-scale computational study of the water imbibition into an artificially generated dual-permeability porous matrix with a fracture attached on top is conducted using a recently improved lattice Boltzmann color-gradient model. Several factors affecting the dynamic countercurrent imbibition processes and the resulting oil recovery have been analyzed, including the water injection velocity, the geometry configuration of the dual permeability zones, interfacial tension, the viscosity ratio of water to oil phases, and fracture spacing if there are multiple fractures. Depending on the water injection velocity and interfacial tension, three different imbibition regimes have been identified: the squeezing regime, the jetting regime, and the dripping regime, each with a distinctively different expelled oil morphology in the fracture. The geometry configuration of the high and low permeability zones affects the amount of oil that can be recovered by the countercurrent imbibition in a fracture-matrix system through transition of the different regimes. In the squeezing regime, which occurs at low water injection velocity, the build-up squeezing pressure upstream in the fracture enables more water to imbibe into the permeability zone closer to the fracture inlet thus increasing the oil recovery factor. A larger interfacial tension or a lower water-to-oil viscosity ratio is favorable for enhancing oil recovery, and new insights into the effect of the viscosity ratio are provided. Introducing an extra parallel fracture can effectively increase the oil recovery factor, and there is an optimal fracture spacing between the two adjacent horizontal fractures to maximize the oil recovery. These findings can aid the optimal design of water-injecting oil extraction in fractured rocks in reservoirs such as oil shale.

Characterization of Volcanic Reservoirs Requires Comprehensive NMR Tests

This article, written by JPT Technology Editor Judy Feder, contains highlights of paper IPTC 19378, “Comprehensive Evaluation of NMR Characteristics of Complex Volcanic Reservoirs With Different Types of Rock Lithology,” by Junchang Sun, Shijie Zhang, Jieming Wang, Hekun Guo, Chun Li, Hongcheng Xu, Sinan Zhu, and Kai Zhao, PetroChina, prepared for the 2019 International Petroleum Technology Conference, Beijing, 26–28 March. The paper has not been peer reviewed. Copyright 2019 International Petroleum Technology Conference. Reproduced by permission. This paper discusses a study undertaken to gain better understanding of nuclear magnetic resonance (NMR) characteristics of volcanic reservoirs with different lithologies. Results of the study confirmed that accurate identification of reservoir-interval lithology, achieved through comprehensive laboratory NMR investigation of the volcanic rock, is a primary prerequisite of correct interpretation of NMR logging of volcanic reservoirs. The research results play an important role in guiding in-depth understanding of NMR characteristics of volcanic reservoirs and the implementation of NMR reservoir evaluation in corresponding areas. Introduction The introduction of NMR to the petroleum industry in the 1990s led to a breakthrough in logging. NMR can distinguish between movable and irreducible fluid, and is currently the only logging technology that can determine reservoir permeability. When used to interpret and evaluate complex reservoirs such as volcanic rocks and low-resistivity oil and gas layers, NMR provides logging analysts with new ideas and techniques to deal with various difficulties. By analyzing the NMR relaxation-time (T2) spectrum of rock plugs at a fully brine-saturated state, the distribution of reservoir pore size can be evaluated, and important reservoir evaluation parameters, including effective porosity, NMR permeability, and movable fluid saturation, can be obtained. Numerous studies have shown that, compared with sandstones and carbonates, volcanic reservoirs are much more complex and heterogeneous because of the special eruption diagenesis mechanism, many types of rock lithology, various mineral compositions, and a broad range of pore sizes. The models currently used for NMR logging interpretation are suitable only for sedimentary reservoirs. Consequently, accurate characterization of volcanic reservoirs using advanced NMR logging requires a comprehensive laboratory NMR investigation of volcanic rock. Materials and Methods For the study described in the complete paper, NMR sample analysis technology was adopted to perform NMR measurements and other related tests on a total of 108 low-permeability rock plugs from the Xushen reservoir of the Daqing field, the Changling reservoir of the Jilin field, and the Dixi reservoir of the Xinjiang volcanic gas field. The rock plugs comprised nine types of lithology representing the main producing formation lithology from the three reservoirs. Tests included CT scans, thin-section petrography, mercury injection, and mineral-composition analysis. Centrifuge tests were conducted with maximum centrifugal forces up to 500 psi to explore the suitable capillary pressure for T2cutoff determination. The paper includes a step-by-step description of the experimental procedure.