Permeability Of Reservoir Rocks Research Articles

The Northwest Geysers EGS Demonstration Project, California: Pre-stimulation Modeling and Interpretation of the Stimulation

The Northwest Geysers Enhanced Geothermal System (EGS) demonstration project aims to create an EGS by directly and systematically injecting cool water at relatively low pressure into a known High Temperature (280–400 °C) Zone (HTZ) located under the conventional (240 °C) geothermal steam reservoir at The Geysers geothermal field in California. In this paper, the results of coupled thermal, hydraulic, and mechanical (THM) analyses made using a model developed as part of the pre-stimulation phase of the EGS demonstration project is presented. The model simulations were conducted in order to investigate injection strategies and the resulting effects of cold-water injection upon the EGS system; in particular to predict the extent of the stimulation zone for a given injection schedule. The actual injection began on October 6, 2011, and in this paper a comparison of pre-stimulation model predictions with micro-earthquake (MEQ) monitoring data over the first few months of a one-year injection program is presented. The results show that, by using a calibrated THM model based on historic injection and MEQ data at a nearby well, the predicted extent of the stimulation zone (defined as a zone of high MEQ density around the injection well) compares well with observed seismicity. The modeling indicates that the MEQ events are related to shear reactivation of preexisting fractures, which is triggered by the combined effects of injection-induced cooling around the injection well and small changes in steam pressure as far as half a kilometer away from the injection well. Pressure-monitoring data at adjacent wells and satellite-based ground-surface deformation data were also used to validate and further calibrate reservoir-scale hydraulic and mechanical model properties. The pressure signature monitored from the start of the injection was particularly useful for a precise back-calculation of reservoir porosity. The first few months of reservoir pressure and surface deformation data were useful for estimating the reservoir-rock permeability and elastic modulus. Finally, although the extent of the calculated stimulation zone matches the field observations over the first few months of injection, the observed surface deformations and MEQ evolution showed more heterogeneous behavior as a result of more complex geology, including minor faults and fracture zones that are important for consideration in the analysis of energy production and the long-term evolution of the EGS system.

Hydraulic unit prediction using support vector machine

Abstract Hydraulic Flow Units or hydraulic units (HUs) concept is becoming popular for grouping reservoir rocks of similar petrophysical properties with the main goal of having a better estimate of permeability. HU approach has an advantage that it addresses the development of permeability in reservoir rocks from fundamentals of geology and physics of flow at pore network scale. The aim of the present study is to predict HUs for the un-cored sections of the wells in a carbonate reservoir using Support Vector Machines (SVMs). HUs for un-cored sections were predicted using wire line logs as input and the associated conventional core values as guides to SVMs. HUs for the core data were identified using three popular correlations such as Kozeny–Carmen (KC) equation, Nooruddin and Hossain equation, and the power law flow unit equation. The experimental results on a Middle East field data show that a better HU prediction accuracy is achieved using Nooruddin and Hossain correlation in comparison with using KC and the power law flow unit correlation. A further analysis to the predicted value reveals that better prediction accuracy is achieved if the granularity of HU class boundary is enlarged to the neighboring classes. Although Nooruddin and Hossain correlation could better relate wire line logs to HUs, however the permeability calculated from the predicted HUs showed less error with the power law flow unit correlation. Considering this, we achieved a maximum of 97% accuracy which encourages the application of SVMs in HU unit prediction using well log data for the un-cored sections of well or for the wells which do not have core data.

Simulation and Prediction of the Rock Permeability of the Depth Delay INET in an Ultra-deep Reservoir

Through the explanation of complex lithology character of a reservoir's bore log, INET is used to get the permeability. INET needs training data, which is composed of a certain number of inputs and the relevant target signals, then with the quick produced results, a comparison can be made among them. As the result shows, the data generated by the INET is much closer to the core data. INET can get the optimal network operating system in a short time and provide an inherent asperity permeability profile. By applying the delay depth network model, two samples were taken for each depth; the trained network can find the relation of present depth point with log parameter of its upper and lower layer and present depth core analysis parameter automatically. INET is a good way for the simulating and predicting of reservoir rock permeability and is also of valuable significance as the study of theoretical approach.

Improving performance of a neural network model by artificial ant colony optimization for predicting permeability of petroleum reservoir rocks

Over recent years, oil and gas exploration has been beloved due to extended needs for petroleum and energy sources. In this way, the capabilities of intelligent techniques are studied by researchers in different fields of petroleum industry and geosciences, whereas it seems that these techniques can improve the prediction accuracy of exploration and production of the hydrocarbon reservoir. The performance indices of the artificial models have proven to be better than the conventional linear and non-linear statistical models. Artificial intelligence models are extremely useful for reservoir characterization, which requires a high-accuracy prediction for a good exploitation of the oil and gas resources. The present paper introduces an optimized neural network (NN) for predicting permeability based on a relatively new swarm intelligent approach, named ant colony optimization. Ant colony optimization (ACO) is a relatively new computational intelligent approach, which was initially inspired by the observation of ants. The number of neurons in hidden layer, weights and bias are optimized in the proposed NN using the ACO. The data of a gas reservoir in the South Pars Gas Field of Iran was used for analyzing the accuracy of optimized NN in a real case study. Finally, to clarify the advantages of the optimized NN, its outcomes were compared with the results of a simple NN model, in which the aforementioned parameters were determined through a try-and-error process. The MSEs of the optimized and simple NN were equal to 7.95 md and 12.84 md, respectively, which correspond to the correlation coefficient (R) of 0.94 and 0.866, respectively.

Extending the Application of a Shale Volume Estimation Formula Derived from Factor Analysis of Wireline Logging Data

A multivariate statistical procedure is developed for the estimation of shale volume in clastic sedimentary formations. The method offers an alternative for extracting the shale content from borehole geophysical measurements. Factor analysis of various well-logging data types generates a new well log that correlates with the shale content of shaly-sandy rocks. The mathematical relationship between shale volume and factor scores is represented by a nonlinear equation, which seems to be applicable for data sets originating from different sedimentary basins. A comparative study is made between three different data sets originating from Hungary and the United States of America in order to check the validity of the proposed empirical formula. Shale volumes predicted from factor analysis are confirmed by estimates from independent deterministic and inverse modeling. Petrophysical information derived by factor analysis of logs recorded in deep wells can be used for a more accurate and reliable estimation of effective porosity and absolute permeability of reservoir rocks, for decreasing the estimation error of inversion estimates and for reducing the ambiguity in the solution of the well-logging inverse problem.

Analysis of drill stem testing technology of the Malm carbonate rocks of the Carpathian Foothills, in the aspect of geological research and exploration decisions

1. InTRoDUcTIonThe credibility of drill stem tests results performed with DST tools depends largely on the technology used. The Polish Oil and Gas Company most commonly use double-cycle drill stem tests, which, in the case of inflow to DST tool oil or reservoir water, enable among others the evaluation of [1, 2]:‒ changes of permeability of reservoir rocks in closer and more distant parts of the near-wellbore area test with DST,‒ change of yield index in the first and in the second sampling cycle,‒ relieving the given horizon of reservoir rocks from the repression of the column of the drilling mud.In the case of natural gas inflow to DST and mud spacer self-acting outflow from DST column, the technology of drill stem test changes from double-cycle to multi-cycle with clas-sical open flow operation. Thanks to open the flow operation, it is possible to remove the mud from bottom hole and declogging the near-wellbore area rocks.The Baker Inflatable type tool allows us to perform selective reservoir test, mostly in open hole sections of boreholes but also in the case of large caverns in borehole walls [1]. Then the inflow of reservoir fluid is from a predetermined interval of wellbore. This allows to shutoff the inflow of bottom water to the DST tool and reduces forming the water cone.

INORGANIC SCALE FORMATION AND ITS INDUCED PERMEABILITY IMPAIRMENT DUE TOWATER INCOMPATIBILITY ISSUE DURING THE WATER INJECTION PROCESS

Due to the different natures of formation and injection waters, especially in seawater injection cases, incompatibility may happen within the reservoir and cause supersaturation and precipitation of some salts. This precipitation may reduce the permeability of reservoir rock from the injector vicinity to far deep in the reservoir. This paper investigates a seawater injection project. First, the scale types and amounts due to different mixing ratios are studied employing commercial software. Then, dynamic injection of seawater into carbonate samples saturated with formation water is performed and the induced damages are analyzed. Finally, the types of scales formed within the core samples are analyzed by scanning electron microscopy and energy dispersive X-ray spectroscopy imaging. Dynamic conditions may change the behavior of scale formation and precipitation. Therefore, summation of the experimentally-observed scales and the software-predicted ones can lead us to scales happening in reality. The water incompatibility induced permeability damage ratio is characterized by an initial constant permeability period where no damage is induced. After that, it experiences a decrease that stabilizes around 2 pore volumes. The higher the permeability, the longer is the initial constant permeability period and the lower is the final induced permeability damage due to larger pore throats. The final stabilization time points to the situation where all of the core sample lengths have experienced maximum scale formation and precipitation. Overall, the high contrast of seawater and formation water raises the probability of scale formation especially of the sulfate type. Moreover, the extent of damage is much more important than the types of scales which should be investigated in each project.

Factors Affecting Hydraulically Fractured Well Performance in the Marcellus Shale Gas Reservoirs

Development of shale gas reservoirs has become an integral part of the North American gas supply. The Marcellus shale reservoir contains large untapped natural gas resources and its proximity to high demand markets along the East Coast of the United State makes it an attractive target for energy development. The economic viability of such unconventional gas development hinges on the effective stimulation of extremely low permeability reservoir rocks. Horizontal wells with multistage hydraulic fracturing technique are the stimulation method of choice and have been successful in shale gas reservoirs. However, the fundamental science and engineering of the process are yet to be fully understood and hence the protocol that needs to be followed in the stimulation process needs to be optimized. There are several factors affecting the hydraulic fracture treatment and the postfracture gas production in shale gas reservoirs. In this paper, we used numerical reservoir simulation techniques and quantified the effect of the following pertinent factors: multiphase flow, proppant crushing, proppant diagenesis, reservoir compaction, and operating conditions on the performance of the designed multistage hydraulic fracturing process. The knowledge generated in this study is expected to enable engineers to better design fracture treatments and operators to better manage the wells in the Marcellus shale gas reservoir.

Permeability alteration induced by drying of brines in porous media

Permeability of reservoir rocks can be strongly altered by salt precipitation induced by drying. Indeed, gas injection in deep saline aquifers leads first to the brine displacement. The liquid saturation decreases near the injection point and reaches a residual water saturation. But at longer time, the water mass transfer to the gas phase by evaporation can become significant and the dissolved salt can precipitate in the porous structure. The solid salts fill the pores and the permeability decreases. Permeability alteration by salting out is a risk of injectivity decline in the context of CO2 geological storage in saline aquifers where high level of gas injection has to be maintained over decades. However, this problem has been poorly investigated. It implies physical processes that are strongly coupled: drying, water and gas flows in the porous structure and precipitation. This work is an experimental investigation aiming at measuring on natural rock samples the permeability alteration induced by convective drying where dry gas is injected through the sample. We show that alteration of permeability is strong and total blockage of the flow is even possible. We also show that the change in porosity due to the solid salt is heterogeneous along the rock samples. A local permeability-porosity relationship has been estimated from the measurements and we could deduce the permeability alteration function of time by modeling the drying dynamic. We show that it starts very early because capillary backflows are extremely efficient in this process to accumulate solid salt near the injection surfaces.

Reactive transport simulation study of geochemical CO2 trapping on the Tokyo Bay model – With focus on the behavior of dawsonite

A long-term (up to 10ka) geochemical change in saline aquifer CO2 storage was studied using the TOUGHREACT simulator, on a 2-dimensional, 2-layered model representing the underground geologic and hydrogeologic conditions of the Tokyo Bay area that is one of the areas of the largest CO2 emissions in the world. In the storage system characterized by low permeability of reservoir and cap rock, the dominant storage mechanism is found to be solubility trapping that includes the dissolution and dissociation of injected CO2 in the aqueous phase followed by geochemical reactions to dissolve minerals in the rocks. The CO2–water–rock interaction in the storage system (mainly in the reservoir) changes the properties of water in a mushroom-like CO2 plume, which eventually leads to convective mixing driven by gravitational instability. The geochemically evolved aqueous phase precipitates carbonates in the plume front due to a local rise in pH with mixing of unaffected reservoir water. The carbonate precipitation occurs extensively within the plume after the end of its enlargement, fixing injected CO2 in a long, geologic period.Dawsonite, a Na–Al carbonate, is initially formed throughout the plume from consumption of plagioclase in the reservoir rock, but is found to be a transient phase finally disappearing from most of the CO2-affected part of the system. The mineral is unstable relative to more common types of carbonates in the geochemical evolution of the CO2 storage system initially having formation water of relatively low salinity. The exception is the reservoir-cap rock boundary where CO2 saturation remains very high throughout the simulation period.

Reservoir rock permeability prediction using support vector regression in an Iranian oil field

Reservoir permeability is a critical parameter for the evaluation of hydrocarbon reservoirs. It is often measured in the laboratory from reservoir core samples or evaluated from well test data. The prediction of reservoir rock permeability utilizing well log data is important because the core analysis and well test data are usually only available from a few wells in a field and have high coring and laboratory analysis costs. Since most wells are logged, the common practice is to estimate permeability from logs using correlation equations developed from limited core data; however, these correlation formulae are not universally applicable. Recently, support vector machines (SVMs) have been proposed as a new intelligence technique for both regression and classification tasks. The theory has a strong mathematical foundation for dependence estimation and predictive learning from finite data sets. The ultimate test for any technique that bears the claim of permeability prediction from well log data is the accurate and verifiable prediction of permeability for wells where only the well log data are available. The main goal of this paper is to develop the SVM method to obtain reservoir rock permeability based on well log data.

Research on Characteristics and Three-Dimension Geologic Model Building of the Chang2 Reservoir, Yanchang Formation in Zhifang Area, Zhidan Oilfield

Through the reservoir of Chang 2 member in Zhifang area, Zhidan oilfield is typical of low porosity and low permeability reservoir rocks, using casting thin sections, scanning electron microscopy and physical analysis, etc., starting with the reservoir characteristics of Chang2 member, we have understood its causes and characteristics of low permeability. Using sequential indicator simulation and based on the target body method, we established the head of the construction of the reservoir model in Chang 2 member, using the sequential Gaussian simulation method combined with phase control principle, a model of reservoir properties in this area was established, Getting a high quality reservoir and field development and deployment of later development and further adjustments to tap the potential pratical guidance.

Evolution of quartz cementation during burial of the Cambrian Mount Simon Sandstone, Illinois Basin: In situ microanalysis of δ18O

The thermal, mechanical, and chemical evolution of a sedimentary basin exerts important controls on porosity and permeability of reservoir rocks. Oxygen isotope ratios of individual diagenetic cements record evidence of this history, but cannot be analyzed accurately by conventional techniques. Recent improvements for in situ analysis by ion microprobe provide high precision and accuracy at a scale of 5–10 μm. In combination with cathodoluminescence imaging, in situ analysis of δ 18 O (quartz) from the Cambrian Mount Simon Sandstone in the Illinois Basin (USA) reveals gradients within single overgrowths of as much as 7.7‰/50 μm. While the inner portions of overgrowths remain approximately constant in δ 18 O across the basin, the δ 18 O of the rim becomes lower with depth. These data suggest that overgrowths formed during burial and heating, possibly with minimal changes in δ 18 O of pore fluids. If δ 18 O(H 2 O) = −3‰, the highest temperature calculated for the rim of an overgrowth is 107 °C at a paleodepth of 3.5 km. The variability both in average δ 18 O of overgrowths and patterns from individual overgrowths corresponds with a geotherm of 30 °C/km, and there is no evidence of quartz precipitation from higher temperature hydrothermal fluids.

Generic Distinguishing Characteristics and Stratigraphic Ranges of Fossil Corallines: An Update

Abstract Corallines or coralline algae are carbonate secreting and strongly calcified red algae of the order Corallinales of division Rhodophyta. Architecturally, the corallines have two groups, the nongeniculate and geniculate coralline forms. Corallines are used as a potential tool for paleoecology, paleoenvironments and paleobathymetry. Coralline algae are builder of porous and permeable carbonate reservoir rocks for hydrocarbon and reefs rich in hydrocarbon. The old approach, ca. prior to 1977, of taxonomy of fossil coralline genera has been replaced by the modern approach that established during the last decade using certain distinguishing features such as arrangement of basal filaments, cell fusions, conceptacle perforations and orientation of filaments around conceptacles of living corallines. The earliest confirmed fossil record of coralline algae is from the Hauterivian (Early Cretaceous) and from the Hauterivian to the Pleistocene 9 nongeniculate coralline genera, namely Distichoplax, Lithophyllum, Lithoporella, Lithothamnion, Mesophyllum, Neogoniolithon, Phymatolithon, Spongites and Sporolithon and 7 geniculate genera, viz. Amphiroa, Arthrocardia, Calliarthron, Corallina, Jania, Metagoniolithon and Subterraniphyllum having different stratigraphic ranges are unequivocally known as fossils. After 1977, we do not have a comprehensive publication giving the generic distinguishing characteristics and stratigraphic ranges of both nongeniculate and geniculate corallines. The present paper gives an update of distinguishing characteristics of fossil coralline algal genera and their stratigraphic ranges.

Advance Water-Flooding to Reduce the Stress Sensitivity Affect on Low Permeability Reservoir Development

Physical simulation experiments were made to research on the stress sensitivity on physical property of low permeability reservoir rocks. The experimental results shown that effective pressure had good exponential relationship with reservoir permeability. Combining with materaial balance method, reservoir engineering and rational deducation was made to reserach on water-flooding timing of low permeability reservoir development. Several production targets were obtained by these method, such as formation pressure, water and oil production, water cut and so on. The results shown that advanced water-flooding was very important in low permeability reservoir development to reduce the bad impact of stress sensitivity on formation permeability and maintain formation pressure.

Application of shear induced structure materials for brine flooding in sandstone oil reservoirs

Shear induced structure (SIS) chemicals need to be used at higher concentrations in brines than with water to obtain the same effect for retardation in higher permeability reservoir rock. A threshold level of between 1 and 2 mM SIS concentration is sufficient to overcome typical salt concentrations (ca. 3%) found in brines. The flow retardation occurs over injection volumes greater than one pore volume suggesting permeability dependent proppant formation. The micellar component is selectively absorbed in porous sandstones (Berea and Bentheim). However the cosolute is only absorbed in the presence of the micellar component. Analysis of the solution viscosities indicates the existence of an extra component of resistance during permeable flow within the sandstone cores. This is attributed to elongational effects. Prior to application, it is necessary to know how much SIS chemical is lost from the aqueous to the organic phase. during the two phase flow associated with water flooding to displace oil. Comparison of contact component transfer shows that more SIS components are lost from the aqueous phase on contact with higher aromatic oils.

Permanent Alteration of Porous Media Wettability from Liquid-Wetting to Intermediate Gas-Wetting

Wettability of Berea and low permeability reservoir rocks are permanently altered from liquid-wetting to intermediate gas-wetting. We use water and decane as model liquid, and air and nitrogen as model gas in the experiments. New chemicals with various functional groups are used in the wettability alteration. We perform compositional analyses of the treated chemical solutions extracted from rock treatment by gas chromatography–mass spectrometry (GCMS) and by inductively coupled plasma-mass spectrometry (ICPMS). The analyses demonstrate reaction between the chemicals and the rock substrate. There is no measurable change in permeability from the chemical reaction for the low molecular weight chemicals. The results reveal the permanent alteration of wettability. Tests are conducted to measure contact angle, spontaneous imbibition, and flow to assess the effect of wettability alteration on flow performance as a function of chemical concentration and functionality. For Berea, the contact angle for the water–air–rock is altered from 0° to ~150° depending on the chemical concentration. For the reservoir rock, the contact angle is altered from ~70° to ~130°. As a result of the treatment, the water flow rate may increase two and a half times for a given pressure drop in the Berea. The permanent alteration of wettability with the new chemicals is intended for prevention of water blocking in gas production from tight reservoirs. Instead of hydraulic fracturing when water is introduced in formations with most of the water retained by the water-wet rocks, one may use the new chemical surfactants in fracturing to avoid water retention for high gas well productivity.

Zeolites in volcanic-igneous hydrothermal systems: a case study of Pauzhetka geothermal field (Kamchatka) and Oligocene Smrekovec volcanic complex (Slovenia)

Production from geothermal reservoirs in volcanic-igneous hydrothermal systems may be disturbed owing to the formation of authigenic minerals that reduce primary porosity and infill fissure systems. Crystallization may be induced by natural processes or human activity related to the reservoir exploitation. In volcanic and volcaniclastic rocks, zeolites and related authigenic silicate minerals commonly develop. Two selected study sites—Pauzhetka geothermal field in Russia and Smrekovec volcanic complex in Slovenia are characterized by extensive development of progressive stage medium- and low-temperature propylitization and zeolitization with similar mineral assemblages that reduced original reservoir rock porosity and permeability. Retrograde and overprinting reactions of argillitization commonly enhance porosity and permeability of rocks, but some other reactions, like from prehnite to laumontite, from laumontite to heulandite, and from laumontite to analcime, encountered in the Smrekovec volcanic complex reduced it appreciably. Retrograde reactions recognized in the study sites were not induced by the temperature drop only, but were accompanied by the change in chemical composition of reacting fluids. Chemical composition of interstitial waters produced from exploitation wells in the Pauzhetka geothermal field indicate that propylitic and zeolite facies alteration is related to Na–Cl, slightly alkaline waters, while argillitization involved acidic thermal waters with more complex ion composition.

Physical Property and Origin of Lowly Permeable Sandstone Reservoir in Chang 2 Division, Zhang-Han Oilfield, Ordos Basin

Lowly permeable sandstone reservoirs play an important role in the exploration and exploitation of natural gas and petroleum in China. The reservoirs are major lowly permeable sandstone reservoirs in Chang 2 division, Yanchang Formation, Upper Triassic in Zhang-Han oilfield, which located in the northern Shaanxi slope of Ordos Basin. According to the distribution and composition of sand beds, integrated measured physical properties, micro-pore structure analysis, cast thin section observation, scanning electron microscopy, the impacts of deposition and diagenesis on porosity evolution are analyzed. The essential diagenesis causing the porosity loss is evaluated quantitatively, and finally the origin mechanisms of low permeability reservoir in Zhang-Han oilfield are discussed. The results show: (1) Fine particle and low compositional maturity arkose are the material foundation of the formation of poor physical property sandstone; (2) The main pore space of reservoir is secondary pores. There are two types of combined pores that including dissolve-residual pores and dissolve-micropores. The porosity values display an approximately normal distribution, and permeability values are asymmetric distribution of the logarithm in lowly permeable sandstones. Their correlation coefficient becomes more and more worse with the decrease of permeability; (3) There are four diagenetic facies, in which three diagenetic facies belong to extra-lowly permeable and ultra-lowly permeable reservoir sandstones and widely distributed, and they are diagenetic lithofacie background of lowly permeability sandstone; (4) In low compositional maturity arkose, its initial porosity is 1/4 lower than conventional reservoir, the secondary and dissolved pores are main pore types of lowly permeable reservoir rocks. It is also a key factor of effective oil-bearing of lowly permeability sandstone.

Measurements of gas permeability and diffusivity of tight reservoir rocks: different approaches and their applications

AbstractPermeability and diffusivity are critical parameters of tight reservoir rocks that determine their viability for commercial development. Current methods for measuring permeability and/or diffusivity may lead to erroneous results when applied to very tight rocks including gas shales, coal, and tight gas sands, as well as rocks considered as seals for nuclear waste repositories and strata for geological sequestration of CO2. The use of He as routinely applied to measure porosity, permeability, and diffusivity may result in non‐systematic errors because of the molecular sieving effect of the fine pore structure to larger molecules such as reservoir gases. Utilizing gases with larger adsorption potentials than He, such as N2, and including all reservoir gases to measure porosity or permeability of rocks with high surface area is a viable alternative, but requires correcting for adsorption in the analyses. This study expands several approaches to measure permeability and diffusivity with considerations for gas adsorption, which has not been explicitly considered in previous studies. We present new models that explicitly correct for adsorption during pulse‐decay measurements of core under reservoir conditions, as well as on crushed samples used to approximate permeability or diffusivity. We also present a method to determine permeability or diffusivity from on‐site drill‐core desorption test data as carried out to determine gas in place in coals or gas shales. Our new approach utilizes late‐time data from experimental pressure‐decay tests, which we show to be more reliable and theoretically (and practically) accurate than the early‐time approach commonly used to estimate gas‐transport properties.