Changes In Reservoir Properties Research Articles

Особенности строения и изменения коллекторских свойств пластов бобриковского горизонта в визейских врезах (на примере месторождений Мелекесской впадин

Особенности строения и изменения коллекторских свойств пластов бобриковского горизонта в визейских врезах (на примере месторождений Мелекесской впадин

Reservoir sequences of the Anabar-Khatanga saddle: Formation conditions and reservoir properties

The reservoir properties of prospective petroleum complexes of the Anabar-Khatanga saddle are characterized on the basis of summarized published data and laboratory studies of drill cores carried out by the authors. The reservoir properties, lithological composition, and textural-structural features are described for every prospective reservoir interval and the formation conditions of sedimentation are characterized. Conclusions are drawn about factors that control the changes of reservoir properties.

Convolutional time-lapse seismic modeling for CO2 sequestration at the Dickman oilfield, Ness County, Kansas

Time-lapse seismic modeling is routinely used to detect the state of hydrocarbon reservoirs at periodic time intervals. The Dickman field located in the U. S. midcontinent provides two possible [Formula: see text] sequestration targets: a regional deep saline reservoir is the primary objective, and a shallower, mature, depleted oil reservoir is a secondary objective. The goal of this work is to characterize and simulate monitoring of the [Formula: see text] movement before, during, and after its injection into these sequestration targets, including fluid flow paths, reservoir property changes, [Formula: see text] containment, and postinjection stability. Seismic images before, during, and after injection would improve understanding of the carbonate sequestration process and management. Our seismic simulation for time-lapse [Formula: see text] monitoring was based on flow simulator output over a 250-year injection and simulation period. The seismic response was accomplished via convolutional (1D) forward modeling. This work will provide an evaluation for the effectiveness of 4D seismic monitoring in providing assurance of long-term [Formula: see text] containment.

Estimation of the Rock Mechanical Properties Using Conventional Log Data in North Rumaila Field

Hydrocarbon production might cause changes in dynamic reservoir properties. Thus the consideration of the mechanical stability of a formation under different conditions of drilling or production is a very important issue, and basic mechanical properties of the formation should be determined.There is considerable evidence, gathered from laboratory measurements in the field of Rock Mechanics, showing a good correlation between intrinsic rock strength and the dynamic elastic constant determined from sonic-velocity and density measurements.The values of the mechanical properties determined from log data, such as the dynamic elastic constants derived from the measurement of the elastic wave velocities in the material, should be more accurate than that determined by direct strength tests with core samples. This can be attributed to the scale effect and sampling disturbances.The aim of this study was to present methods of determining measures of some mechanical properties, from available well log data (conventional sonic, density, and gamma ray) for a well in North Rumaila field.The mechanical properties include formation strength and Poisson’s ratio. For the formation strength, combined elastic modulus (Ec) and shear modulus (G) were determined. The Poisson’s ratio was determined by using three different techniques to permit the accuracy of their values. The elastic modulus, shear modulus, and Poisson’s ratio were then correlated with depth and effective stress.The results show that combined correlations are important source of the prediction of overpressure zones which represent a major problem encountered in drilling and production process.

Alaskan Heavy Oil: First CHOPS at an Untapped Arctic Resource

This article, written by Assistant Technology Editor Karen Bybee, contains highlights of paper SPE 133592, ’Alaskan Heavy Oil: First CHOPS at a Vast, Untapped Arctic Resource,’ by J.P. Young, SPE, W.L. Mathews, SPE, and E.J. Hulm, SPE, BP Exploration Alaska, originally prepared for the 2010 SPE Western Regional Meeting, Anaheim, California, 27-29 May. The paper has not been peer reviewed. Alaska’s North Slope is a world-class petroleum resource basin with two of the largest producing fields in North America, Prudhoe Bay and Kuparuk River unit. What is not widely known is the vast resource of heavy oil above these reservoirs. Although comparable in size to these fields, it remains untapped as a result of the complexity of producing heavy oil in an arctic environment. The keys to commercializing this heavy-oil resource are primarily technology and favorable economics. Introduction The total North Slope heavy-oil resource is defined by approximately 1,500 wells that penetrate the Ugnu sands for deeper targets and multiple high-quality 3D-seismic surveys. Resource size ranges from 18 to 27 billion bbl of oil in place, and the oil is found in multiple reservoir zones extending across the basin. Initial appraisal is focused on the 12 to 18 billion bbl within the Lower Ugnu (M-sand) reservoirs. The Ugnu structure is characterized by a normal-faulted monoclinal dip toward the northeast. The depth of the Ugnu pool varies from 4,500 ft in the east to 3,000 ft in the west. Multiple fault families are present, as indicated by 3D seismic. The faults tend to compartmentalize the Ugnu reservoirs by providing effective updip and lateral seals. Lower Ugnu oil quality improves to the east, corresponding to increased burial depth from west to east. The deeper, less-viscous oil in the east is believed to be suited to simple “cold”-production techniques that exploit solution-gas drive. The shallower, heavier oil in the west is believed to be suited to energy-intensive thermal techniques that heat the oil in situ. Reservoir-Performance Variability Excluding mechanical issues, most variation in well rates and recovery is likely to be associated with changes in key reservoir and fluid properties. The Lower Ugnu reservoir sands are highly unconsolidated, which limits the ability to acquire quality core samples and measure key reservoir parameters accurately. In addition, the sands were deposited as fluvial-deltaic channels, which are among the most heterogeneous reservoir types.

Technology Focus: Deepwater Projects (June 2010)

Technology Focus Deep water can be an unforgiving environment, one mistake can cost millions and in the worst case cost lives. So why are so many companies willing to take the risk and spend billions on new deepwater fields? Perhaps it is the billions of barrels of hydrocarbon that have been discovered and produced over the last 20 years and the prize of unlocking the latest Lower Tertiary trend in the Gulf of Mexico (GOM) with estimates up to 80 billion bbl. The ability to overcome the challenges and successfully develop and produce this latest trend will not be easy. So what are the big challenges for these newly discovered fields and how will they be overcome? If we focus on the challenges and what it will take from the completion side to unlock this new trend, there are three major components that need to be addressed: rock quality, high pressure, and depth. For the first time in deepwater GOM, the reservoir rock will not provide naturally commercial rates and will require stimulation. Some say it is like onshore fracturing, but those that understand the Lower Tertiary realize that this reservoir is not like most onshore reservoirs. There really are no good analogs. To determine the optimum completion efficiently, numerical models that can grid to a completion-component level, incorporate a fracture, and honor the reservoir-property changes with pressure is a must. Why? A big difference between land and offshore is that offshore cannot afford many partially successful look-back analogs. Each well has to be right the first time. High pressures (~25,000 psi) and depths, >30,000 ft, require great attention to detail for each piece of equipment. Pressures, both absolute and differential, must be understood through all phases: initial installation, unloading, production, shutdowns, artificial lift, recompletions, and abandonment. Solutions become a balance between minimizing yield strength of the high-yield nickel-alloy metals and maximizing inner and outer diameters. Depths in excess of 30,000 ft bring challenges that will have to be dealt with for the life of the well. Great depths bring high tubular-stress loads and thus limits to coil and other intervention tools. First-time success of high-pressure equipment requires involvement of experienced engineers from both the operator and the service company from design and manufacturing to qualification. It also requires management sponsorship from both companies to ensure that it is a high priority. Because everything must work and work the first time, front-end loading before first oil can take years of detailed engineering work and requires highly skilled engineers who can design and develop equipment for pressures and depths that stretches past current technology. Engineers must have the expertise to model, design, and execute a sandface completion that provides commercial rates and recoveries. Hence, as in past deepwater-field developments, there are challenges to overcome, but with the right people, it is possible. Deepwater Projects additional reading available at OnePetro: www.onepetro.org SPE 124535 • “Flow Assurance Design and Initial Operating Experience From Blind Faith in Deepwater Gulf of Mexico” by S. Subramanian, SPE, Chevron, et al. SPE 124857 • “A Unified, Multidisciplinary Approach to the Planning and Design of Deepwater Waterflooding Projects” by Fady R. Chaban, SPE, GATE LLC, et al. SPE 128190 • “Drilling Deep in Deep Water: What It Takes to Drill Past 30,000 ft” by Crispin Chatar, Schlumberger, et al.

Elastic-wave sensitivity propagation

Effective and reliable reservoir monitoring is critically important for optimizing oil/gas production and ensuring safe geologic carbon sequestration. It requires an optimal sensor deployment that uses a minimum number of sensors to record the most significant information resulting from reservoir property changes. Conventional monitoring survey designs are typically based on seismic-wavefield illumination analyses, which cannot alone determine the best receiver locations for effective and reliable monitoring of reservoir property changes. We propose a new approach for designing seismic monitoring surveys by analyzing the sensitivities of elastic waves with respect to reservoir geophysical property changes. The method is based on differentiating the elastic-wave equations with respect to geophysical parameters. The resulting sensitivity equations are solved simultaneously with the elastic-wave equations using a finite-difference scheme. Numerical studies confirm that time-lapse seismic survey designs based on elastic-wave sensitivity analysis can be totally different from those based on elastic-wavefield illuminations. For time-lapse seismic monitoring, receivers should be placed at locations where elastic-wave sensitivities are significant. Modeling of elastic-wave sensitivity propagation provides a fundamental tool for effective seismic monitoring survey designs.

Target-oriented joint least-squares migration/inversion of time-lapse seismic data sets

Two related formulations are proposed for target-oriented joint least-squares migration/inversion of time-lapse seismic data sets. Time-lapse seismic images can be degraded when reservoir overburden is complex or when acquisition geometries significantly differ, because the migration operator does not compensate for the resulting amplitude and phase distortions. Under these circumstances, time-lapse amplitudes are poor indicators of production-related changes in reservoir properties. To correct for such image degradation, time-lapse imaging is posed as joint inverse problems that utilize concatenations of target-oriented approximations to the linear least-squares imaging Hessian. In both formulations, spatial and temporal constraints ensure inversion stability and geologically consistent time-lapse images. Using two numerical time-lapse data sets, we confirmed that these formulations can attenuate illumination artifacts caused by complex overburden or geometry differences, and that they yield better-quality images than obtainable with migration.

Changes in reservoir properties from injection of supercritical CO2 into coal seams — A laboratory study

article i nfo Two Australian Permian coals of similar rank but different texture, one predominantly dull and the other predominantly bright, were investigated in laboratory experiments to assess changes in reservoir properties following exposure to supercritical CO2 (SCCO2) and water. Both powdered coal (0.180-0.220 mm) and small cubes (15 mm to a side) were tested in a high-pressure (HP) batch reactor for up to 120 h. Two reaction fluids were used, each on separate sister coal samples: de-ionised water (DH2O) only, and a SCCO2 and DH2O mixture. Properties were measured before and after treatment with: high-pressure CO2 adsorption isotherms (storage capacity); helium pycnometry, mercury porosimetry and low-pressure (LP) CO2 adsorption (density, porosity and PSD effects); leachate chemical analysis for dissolved mineral matter; and water and CO2 permeabilities at in situ conditions during core flood experiments on an 80 mm cube. Micro and meso porosities for both coals showed significant increases after reactions with the SCCO2 and DH2O mixture. The macroporosity decreased significantly for the dull coal, but increased marginally for the bright coal. Total accessible porosity for dull coal showed virtually no change (0.5%); the bright coal exhibited 3.4% increase from a pre-treatment total porosity of 11.0%. On powdered samples reacted with the mixture, 80%+ increases in internal surface areas, measured using LP CO2 sorption at 0 °C, were noted for both coals. The HP CO2 excess adsorption isotherms on both coals increased after treatment, varying with pressure level, coal type and coal texture. The core flood tests indicated the permeability to CO2, after a waterflood stage, increased significantly. The second stage waterflood exhibited an over 600% increase on the pre-CO2 first stage waterflood permeability. These combined results indicate that mineral matter in Permian coals is dissolved and mobilized by the carbonic acid formed during CO2 dissolution in water, leading to increased porosity, permeability and HP CO2 excess adsorption.

Changes of deformational and reservoir properties of arenaceous-argillaceous rocks due to operation of underground gas storage facilities

This paper discusses issues of the decline of the reservoir properties of arenaceous-argillaceous rocks as a result of declining porosity due to long-term operation of underground gas storage facilities. An analysis of the many-year operation of storage facilities, as well as calculation, has revealed that the active capacity of a storage reservoir gradually decreases under certain conditions of underground storage operations. We performed a series of experiments with model specimens in order to support the hypothesis of decreasing reservoir (capacity-filtration) properties because of changes in the value and structure of the pore space. These experiments showed that the cyclic loading and unloading of arenaceous-silty rocks during long-term operation of underground gas storage facilities can significantly decrease the reservoir parameters of reservoirs created within worked out gas-and-gas condensate fields. Laboratory studies of model specimens corresponding to feldspar sandstone in their composition, porosity, and strength proved that porosity considerably decreases in such reservoirs at actually existing values of formation pressure. Tests of sand performed under conditions close to those existing during the development of hydrocarbon fields also showed that their permeability gradually decreases in the process of cyclic changes of effective pressure.

Time-lapse inversion and geomechanical modelling of the South Arne field

Time-lapse seismic technology is routinely used to monitor production-related reservoir changes. Indeed, the analysis of observed seismic 4D effects and estimation of the corresponding elastic attributes provide valuable information about the dynamics of the reservoir (saturation, pore pressure), particularly away from existing wells, into areas where production data is ‘blind.’ However, the interpretation of time-lapse response can be complex as different reservoir property changes can lead to the same variation in a given elastic parameter. This is particularly true for chalk fields undergoing porosity reduction in addition to change in fluid and pore pressure depletion.

Listening to the Reservoir—Interpreting Data From Permanent Downhole Gauges

Distinguished Author Series articles are general, descriptive representations that summarize the state of the art in an area of technology by describing recent developments for readers who are not specialists in the topics discussed. Written by individuals recognized as experts in the area, these articles provide key references to more definitive work and present specific details only to illustrate the technology. Purpose: to inform the general readership of recent advances in various areas of petroleum engineering. Abstract The permanent downhole pressure gauge is a class of tool that has become popular in the industry. These tools are installed during the well completion and provide a continuous record of pressure changes during production. Permanent downhole gauges (PDGs) have potential to provide more information than is available with traditional well testing, which is carried out for a relatively short duration. PDGs may provide useful information regarding changes in reservoir properties or well conditions with time as the reservoir is produced. However, interpretation of PDG data is a new problem. Unlike the traditional well test in which "disturbances" in the reservoir (i.e., rate changes) are created and pressure and rates are both known, the changes in rates associated with the record from the PDG may not be known. Moreover, the dynamic changes in the reservoir, along with changes in the flowing temperature or changes in the gauge itself, make the data more complicated to interpret. Introduction Developing petroleum resources in an optimal manner requires making many complex decisions on the basis of expectations of future reservoir performance. Central to forecasting reservoir performance is creation and calibration of a reservoir model. These interrelated tasks generally are known as reservoir description and history matching. Most data used for history matching are in the form of surface-measured rates and cumulative volumes of production (oil, gas, and water) and injection (water and gas). However, improving both the creation of a reservoir model and its calibration to replicate measured reservoir history requires collecting measurements from the reservoir itself. In many cases, these downhole data include measurements of pressure, flow rate, and temperature as functions of time. Traditionally, such measurements were made with wireline gauges. However, during the past 20 years, the application of permanently installed gauges has become increasingly common. As of 2006, the number of permanently installed gauges is probably in excess of 10,000 worldwide [Chorneyko (2006) quotes more than 1,000 for one major oil company alone].

Reservoir neural state reconstruction and chaotic time series prediction

ESN(Echo state network) is a new type of recurrent neural network, which is based on the “reservoir”. ESN has been proved to be significantly efficient to deal with some chaotic time series prediction tasks. This paper makes an analysis of the current iterative prediction method based on “reservoir”, and points out some problems in theory and the obstacles in application. And then, a direct prediction method is proposed, which relates the prediction origin and prediction horizon directly. The direct method does not close the loop in the process of prediction, so there are no such problems as instability and error accumulation. The simulation results show how the reservoir property changes when the loop is closed in the iterative prediction, and then demonstrate the feasibility of the direct prediction method in application to the Mackey-Glass benchmark prediction problem.

A Study of The Method for Time‐Lapse Seismic Monitoring of Waterflooding Front and its Application

AbstractMonitoring recovery processes is one of the keys to optimize reservoir management and improve production efficiency. Water‐flooding causes changes of reservoir properties (such as pressure, saturation, porosity etc.) and then the changes of the reservoir elastic parameters. Based on the law of fluid movement, we discuss the characteristics of seismic response of water‐flooding reservoir by forward modeling and give a definition for the water‐flooding front. A method based on differential amplitude and singularity value analysis is presented to monitor the front by the time‐lapse seismic method. The efficiency of the method has been tested by a synthetic example. We applied the method to a field data from eastern China. Two latter drilling confirmed the accuracy of the estimated water‐flooding front. The results also indicate that the distribution of residual oil could be predicted effectively from time‐lapse seismic method by integrating the water‐flooding front and the initial reservoir characterization.

Multi-scale geophysical data analysis using the eigenimage discrete wavelet transform

Discrete wavelet transforms are useful in a number of signal-processing applications. When non-stationary noise spans most wavelet scales, simple rejection of certain scales in the wavelet domain often fails to achieve the desired effect because of strong intra-scale coupling effects. To improve the scale resolution, a joint function of time, scale and eigenvalue that describes the energy density or intensity of a signal simultaneously in the wavelet and eigenimage domains is constructed. A hybrid method, which decomposes eigenimages in the wavelet domain, is developed and tested on field data with a variety of noise types. Several illustrative examples examine the ability of wavelet transforms to resolve features at several scales and the feasibility of combining these transforms with eigenstructure seismic interference cancelling techniques. Successful applications to time-lapse seismic reservoir monitoring are presented. In reservoir monitoring, the scale-dependent properties of the eigenstructure of the 4D data covariance matrix enable us to extract the low-frequency time-lapse signal that is the result of internal diffusive losses caused by fluid flow. The method also gives excellent results in coherent or random noise attenuation, wavefield separation, low-frequency processing, optimal velocity smoothing, data upscaling, and integration of well logs and seismic data. Particular benefits are due to trace matching for multiple subtraction and 4D cross-equalization that extracts subtle variations due to changes in reservoir properties from a signal whose spectral density is not stationary.

半径方向の貯留層物性変化を有する坑井モデルの近似解法とその応用―数値計算における安定性および速度の向上―

The purpose of this study is to develop practical and versatile analytical solutions of well testing for the reservoir with radial property variation. Here, “practical” means that the calculation cost is not so expensive and “versatile” means that the algorisms are numerically stable”. Two analytical solutions for this problem are presented and improved. The first is the perturbative solution which was introduced by Oliver. Although this solution could treat the continuous function of permeability variation, the first order perturbation remains some errors when the center of the perturbation is set to constant. Thus, we develop a new function to estimate an adequate average permeability which should be applied in order to obtain the good approximation of pressure calculation. The result is excellent; however, this solution is a little tedious to apply for the porosity variation problems. In addition, it is difficult to expand this solution for the problem that the reservoir property changes with time. The second solution is multi-composite solution which is appeared in several papers. “Multi-composite model” treats of permeability and porosity variation as stair-step functions, however, the excellent approximation will be obtained on the condition that the “steps” are enough fine. The fine steps require high calculation cost. This paper presents several mathematical techniques in order to save this cost as well as to obtain numerical stability. Moreover, “Stepwise approach” enables us to treat the time dependent reservoir parameter, such as permeability change with time. Because “Stepwise approach” does not require any superposition of rate, calculation speed is very fast even in the case that production rate is frequently changed.

Streamline-Based Production-Data Integration in Naturally Fractured Reservoirs

This article, written by Technology Editor Dennis Denney, contains highlights of paper SPE 89914, "Streamline-Based Production-Data Integration in Naturally Fractured Reservoirs," by Mishal Al-Harbi, SPE, Hao Cheng, SPE, Zhong He, and Akhil Datta-Gupta, SPE, Texas A&M U., prepared for the 2004 SPE Annual Technical Conference and Exhibition, Houston, 26-29 September. Streamline-based models have shown great potential in reconciling high-resolution geologic models with production data. Use of streamline-based production-data integration has been extended to naturally fractured reservoirs. A dual-porosity streamline model was used for fracture-flow simulation by treating the fracture and matrix as separate continua connected through a transfer function. The sensitivities that define the relationship between reservoir properties and the production response in fractured reservoirs were computed analytically. The production-data integration was carried out with a generalized travel-time inversion. Introduction Natural fractures play a significant role in subsurface flow and transport of fluids. Seismic imaging and horizontal drilling have revealed the extent of fractures in many reservoirs and enabled operators to use novel ways to use fracture connectivity to enhance recovery. The number of reservoirs that are considered naturally fractured has risen significantly, increasing the need for robust fracture-characterization methods that integrate both static and dynamic data. Discrete-fracture-network (DFN) techniques map fracture planes in 3D space by use of statistical properties of fracture swarms, fracture-network geometry, and flow characteristics. DFN models can incorporate complex-fracture patterns by use of field-data sources such as cores, well logs, borehole images, seismics, and geomechanics. Although the DFN models can reproduce very realistic fracture geometry, these models must be conditiond to dynamic data (such as well-test, tracer, and production data) to reproduce the flow behavior in the reservoir. Such conditioning is particularly important for fractured reservoirs because only a few of the fractures in the DFN model might carry most of the fluid flow. Streamline models have shown great potential in integrating dynamic data into high-resolution geologic models. Streamline models can determine the sensitivity of the production data to reservoir parameters such as porosity and permeability. These sensitivities are partial derivatives that quantify how the production response will be affected by changes in reservoir properties. Typically, integrating dynamic data into reservoir models involves solving an inverse problem in which sensitivities play a key role. Streamline-based sensitivities were used in conjunction with a generalized travel-time-inversion method to integrate production data into geologic models.

When 4D seismic is not applicable: Alternative monitoring scenarios for the Arab‐D reservoir in the Ghawar Field

ABSTRACTGhawar, the largest oilfield in the world, produces oil from the Upper Jurassic Arab‐D carbonate reservoir. The high rigidity of the limestone–dolomite reservoir rock matrix and the small contrast between the elastic properties of the pore fluids, i.e. oil and water, are responsible for the weak 4D seismic effect due to oil production. A feasibility study was recently completed to quantify the 4D seismic response of reservoir saturation changes as brine replaced oil. The study consisted of analysing reservoir rock physics, petro‐acoustic data and seismic modelling. A seismic model of flow simulation using fluid substitution concluded that time‐lapse surface seismic or conventional 4D seismic is unlikely to detect the floodfront within the repeatability of surface seismic measurements. Thus, an alternative approach to 4D seismic for reservoir fluid monitoring is proposed. Permanent seismic sensors could be installed in a borehole and on the surface for passive monitoring of microseismic activity from reservoir pore‐pressure perturbations. Reservoir production and injection operations create these pressure or stress perturbations. Reservoir heterogeneities affecting the fluid flow could be mapped by recording the distribution of epicentre locations of these microseisms or small earthquakes. The permanent borehole sensors could also record repeated offset vertical seismic profiling surveys using a surface source at a fixed location to ensure repeatability. The repeated vertical seismic profiling could image the change in reservoir properties with production.

Reactive flow and permeability prediction — numerical simulation of complex hydrogeothermal problems

Abstract Simulating complex flow situations in hydrogeothermal reservoirs requires coupling of flow, heat transfer, transport of dissolved species, and heterogeneous geochemistry. We present results of simulations for typical applications using the numerical simulator SHEMAT/Processing SHEMAT. Heat transfer is non-linear, since all thermal fluid and rock properties depend on temperature. Due to the coupling of fluid density with both temperature and concentrations of dissolved species, the model is well suited to simulate density-driven flow. Dissolution and precipitation of minerals are calculated with an improved version of the geochemical modelling code PHRQPITZ, which accurately calculates geochemical reactions in brines of low to high ionic strength and temperatures of 0–150°C. Changes in pore space structure and porosity are taken into account by updating permeability with respect to porosity changes due to precipitation and dissolution of minerals. This is based on a novel relationship between porosity and permeability, derived from a fractal model of the pore space structure and its changes due to chemical water — rock interaction. A selection of model studies performed with SHEMAT completes the review. Examples highlight both density-driven and reactive flow with permeability feedback. With respect to the former, the thermohaline free convection Elder’s problem, and density-driven free convection in a coastal aquifer with geothermal exploitation, are considered. Mineral redistribution and associated permeability change during a core flooding experiment; reaction front fingering in reservoir sandstone; and long-term changes in reservoir properties during the operation of a geothermal installation, are all considered in relation to reactive flow with permeability feedback.

Repeated seismic reflection measurements in the Kakkonda geothermal field

Temporal variations in seismic reflection responses apparently caused by changes within a geothermal reservoir have been detected in the Kakkonda field, where production wells were shut in prior to annual power plant maintenance. Three seismic surveys were carried out during a 12-day period spanning the shut-in period. Receivers were deployed without replanting throughout the surveys, providing good data acquisition repeatability. We applied prestack time migration (PSTM) to each of the three seismic data sets and calculated the cross-correlation coefficients between PSTM sections. Our results indicate that the reservoir changes associated with shut-in are large enough to be seismically detectable. The region over which the seismic response changed corresponds to the zone of geothermal fluid flow paths inferred from reservoir temperatures and geochemical data. We have also compared our cross-correlation maps with the epicenters of micro-earthquakes, which are inferred to indicate the existence of fractured zones. Dense regions of micro-earthquake activity lie within the seismically identified zone of changes in reservoir properties. We demonstrate the feasibility of repeated seismic surveys in providing substantial improvements in temporal resolution during geothermal reservoir monitoring.