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

Ghawar, 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.     

Controlled‐source electromagnetic monitoring of reservoir oil saturation using a novel borehole‐to‐surface configuration

To advance and optimize secondary and tertiary oil recovery techniques, it is essential to know the areal propagation and distribution of the injected fluids in the subsurface. We investigate the applicability of controlled‐source electromagnetic methods to monitor fluid movements in a German oilfield (Bockstedt, onshore Northwest Germany) as injected brines (highly saline formation water) have much lower electrical resistivity than the oil within the reservoir. The main focus of this study is on controlled‐source electromagnetic simulations to test the sensitivity of various source–receiver configurations. The background model for the simulations is based on two‐dimensional inversion of magnetotelluric data gathered across the oil field and calibrated with resistivity logs. Three‐dimensional modelling results suggest that controlled‐source electromagnetic methods are sensitive to resistivity changes at reservoir depths, but the effect is difficult to resolve with surface measurements only. Resolution increases significantly if sensors or transmitters can be placed in observation wells closer to the reservoir. In particular, observation of the vertical electric field component in shallow boreholes and/or use of source configurations consisting of combinations of vertical and horizontal dipoles are promising. Preliminary results from a borehole‐to‐surface controlled‐source electromagnetic field survey carried out in spring 2014 are in good agreement with the modelling studies.     

Monitoring viscosity changes from time‐lapse seismic attenuation: case study from a heavy oil reservoir

Heating heavy oil reservoirs is a common method for reducing the high viscosity of heavy oil and thus increasing the recovery factor. Monitoring of these viscosity changes in the reservoir is essential for delineating the heated region and controlling production. In this study, we present an approach for estimating viscosity changes in a heavy oil reservoir. The approach consists of three steps: measuring seismic wave attenuation between reflections from above and below the reservoir, constructing time‐lapse Q and Q^?1 factor maps, and interpreting these maps using Kelvin–Voigt and Maxwell viscoelastic models. We use a 4D relative spectrum method to measure changes in attenuation. The method is tested with synthetic seismic data that are noise free and data with additive Gaussian noise to show the robustness and the accuracy of the estimates of the Q‐factor. The results of the application of the method to a field data set exhibit alignment of high attenuation zones along the steam‐injection wells, and indicate that temperature dependent viscosity changes in the heavy oil reservoir can be explained by the Kelvin–Voigt model.     

Integrating gravimetric and interferometric synthetic aperture radar data for enhancing reservoir history matching of carbonate gas and volatile oil reservoirs

Reservoir history matching is assuming a critical role in understanding reservoir characteristics, tracking water fronts, and forecasting production. While production data have been incorporated for matching reservoir production levels and estimating critical reservoir parameters, the sparse spatial nature of this dataset limits the efficiency of the history matching process. Recently, gravimetry techniques have significantly advanced to the point of providing measurement accuracy in the microgal range and consequently can be used for the tracking of gas displacement caused by water influx. While gravity measurements provide information on subsurface density changes, i.e., the composition of the reservoir, these data do only yield marginal information about temporal displacements of oil and inflowing water. We propose to complement gravimetric data with interferometric synthetic aperture radar surface deformation data to exploit the strong pressure deformation relationship for enhancing fluid flow direction forecasts. We have developed an ensemble Kalman‐filter‐based history matching framework for gas, gas condensate, and volatile oil reservoirs, which synergizes time‐lapse gravity and interferometric synthetic aperture radar data for improved reservoir management and reservoir forecasts. Based on a dual state–parameter estimation algorithm separating the estimation of static reservoir parameters from the dynamic reservoir parameters, our numerical experiments demonstrate that history matching gravity measurements allow monitoring the density changes caused by oil–gas phase transition and water influx to determine the saturation levels, whereas the interferometric synthetic aperture radar measurements help to improve the forecasts of hydrocarbon production and water displacement directions. The reservoir estimates resulting from the dual filtering scheme are on average 20%–40% better than those from the joint estimation scheme, but require about a 30% increase in computational cost.     

Multi‐transient electromagnetic repeatability experiment over the North Sea Harding field‡

We present results of synthetic time‐lapse and real repeatability multi‐transient electromagnetic surveys over the North Sea Harding field. Using Archie's law to convert porosity and fluid saturation to resistivity we created 3D isotropic models of the reservoir resistivity at different stages of production from the initial state in 1996 through to complete hydrocarbon production by 2016 and, for each stage, we simulated an east‐west transient electromagnetic survey line across Harding. Unconstrained 1D full‐waveform Occam inversions of these synthetic data show that Harding should be detectable and its lateral extent reasonably well‐defined. Resistivity changes caused by hydrocarbon production from initial pre‐production state to production of the oil rim in 2011 are discernible as are significant changes from 2011–2016 during the modelled gas blowdown phase. The 2D repeatability surveys of 2007 and 2008 tied two wells: one on and the other off the structure. Between the two surveys the segment of the field under investigation produced 3.9 million barrels of oil – not enough to generate an observable time‐lapse electromagnetic anomaly with a signal‐to‐noise ratio of 40 dB. Processing of the 2007 and 2008 data included deconvolution for the measured source current and removal of spatially‐correlated noise, which increased the signal‐to‐noise ratio of the recovered impulse responses by about 20 dB and resulted in a normalized root‐mean‐square difference of 3.9% between the data sets. 1D full‐waveform Occam inversions of the real data showed that Harding was detectable and its lateral extent was also reasonably well‐defined. The results indicate that the multi‐transient electromagnetic method is suitable for exploration, appraisal and monitoring hydrocarbon production.     

Feasibility of borehole ambient noise interferometry for permanent reservoir monitoring

The analysis of seismic ambient noise acquired during temporary or permanent microseismic monitoring campaigns (e.g., improved/enhanced oil recovery monitoring, surveillance of induced seismicity) is potentially well suited for time‐lapse studies based on seismic interferometry. No additional data acquisition required, ambient noise processing can be automatized to a high degree, and seismic interferometry is very sensitive to small medium changes. Thus there is an opportunity for detection and monitoring of velocity variations in a reservoir at negligible additional cost and effort. Data and results are presented from an ambient noise interferometry study applied to two wells in a producing oil field in Romania. Borehole microseismic monitoring on three component geophones was performed for four weeks, concurrent with a water‐flooding phase for improved oil recovery from a reservoir in ca. 1 km depth. Both low‐frequency (2 Hz–50 Hz) P‐ and S‐waves propagating through the vertical borehole arrays were reconstructed from ambient noise by the virtual source method. The obtained interferograms clearly indicate an origin of the ambient seismic energy from above the arrays, thus suggesting surface activities as sources. It is shown that ambient noise from time periods as short as 30 seconds is sufficient to obtain robust interferograms. Sonic log data confirm that the vertical and horizontal components comprise first arrivals of P‐wave and S‐waves, respectively. The consistency and high quality of the interferograms throughout the entire observation period further indicate that the high‐frequency part (up to 100 Hz) represents the scattered wave field. The temporal variation of apparent velocities based on first‐arrival times partly correlates with the water injection rate and occurrence of microseismic events. It is concluded that borehole ambient noise interferometry in production settings is a potentially useful method for permanent reservoir monitoring due to its high sensitivity and robustness.     

Vertical seismic profiling using a daisy‐chained deployment of fibre‐optic cables in four wells simultaneously – Case study at the Ketzin carbon dioxide storage site

The geological storage of carbon dioxide is considered as one of the measures to reduce greenhouse gas emissions and to mitigate global warming. Operators of storage sites are required to demonstrate safe containment and stable behaviour of the storage complex that is achieved by geophysical and geochemical monitoring, combined with reservoir simulations. For site characterization, as well as for imaging the carbon dioxide plume in the reservoir complex and detecting potential leakage, surface and surface‐borehole time‐lapse seismic monitoring surveys are the most widespread and established tools. At the Ketzin pilot site for carbon dioxide storage, permanently installed fibre‐optic cables, initially deployed for distributed temperature sensing, were used as seismic receiver arrays, demonstrating their ability to provide high‐resolution images of the storage formation. A vertical seismic profiling experiment was acquired using 23 source point locations and the daisy‐chained deployment of a fibre‐optic cable in four wells as a receiver array. The data were used to generate a 3D vertical seismic profiling cube, complementing the large‐scale 3D surface seismic measurements by a high resolution image of the reservoir close to the injection well. Stacking long vibro‐sweeps at each source location resulted in vertical seismic profiling shot gathers characterized by a signal‐to‐noise ratio similar to gathers acquired using geophones. A detailed data analysis shows strong dependency of data quality on borehole conditions with significantly better signal‐to‐noise ratio in regions with good coupling conditions.     

Improved microseismic event location by inclusion of a priori dip particle motion: a case study from Ekofisk

Microseismic monitoring in petroleum settings provides insights into induced and naturally occurring stress changes. Such data are commonly acquired using an array of sensors in a borehole, providing measures of arrival times and polarizations. Events are located using 1D velocity models, P‐ and S‐wave arrival times and the azimuths of P‐wave particle motions. However in the case of all the sensors being deployed in a vertical or near‐vertical borehole, such analysis leads to an inherent 180° ambiguity in the source location. Here we present a location procedure that removes this ambiguity by using the dip of the particle motion as an a priori information to constrain the initial source location. The new procedure is demonstrated with a dataset acquired during hydraulic fracture stimulation, where we know which side of the monitoring well the events are located. Using a 5‐step location procedure, we then reinvestigate a microseismic data set acquired in April 1997 at the Ekofisk oilfield in the North Sea. Traveltimes for 2683 candidate events are manually picked. A noise‐weighted analytic‐signal polarization analysis is used to estimate the dip and azimuth of P‐wave particle motions. A modified t‐test is used to statistically assess the reliability of event location. As a result, 1462 events are located but 627 are deemed to be statistically reliable. The application of a hierarchal cluster analysis highlights coherent structures that cluster around wells and inferred faults. Most events cluster at a depth of roughly 3km in the Ekofisk chalk formation but very little seismicity is observed from the underlying Tor chalk formation, which is separated from the Ekofisk formation by an impermeable layer. We see no evidence for seismicity in the overburden but such events may be too distant to detect. The resulting picture of microseismicity at Ekofisk is very different from those presented in previous studies.     

井间电磁法综述

地面电磁法在实际工作中在很大程度上受到了探测深度和分辨率的限制.为了克服这些缺点,出现了井间电磁法.井间电磁法指的是在两个(或多个)钻孔中分别发射或接收电磁波信号,利用电磁波信号进行成像并探测井间物理性质的地球物理方法.由于发射机和接收机可以分别放置在很深钻孔中,其具有大透距、大探测深度的特点,因而广泛应用于工程环境物探、矿产勘查、石油勘探等中.针对不同的应用,产生了各具特点的一些特殊方法,包括井间无线电波成像、跨孔雷达、井间电磁成像.井间无线电波成像仪目前只测量电场强度数据,工作频率低,一般是单频的电磁波,频率范围通常在1 kHz至10 MHz.由于缺少走时数据修正射线路径,井间无线电波成像主要是进行基于直射线追踪的衰减层析成像.井间无线电波成像既可用于工程与环境地球物理也可用于找矿.跨孔雷达是钻孔雷达的一种探测方式,用高频电磁脉冲探测两个井孔间介电常数和电导率的变化.跨孔雷达层析成像也叫地质雷达CT,既可进行走时成像,还可进行衰减成像.一般来说,地质雷达CT的电磁波工作频率较高,中心频率通常在10 MHz和1 GHz之间,因此在分辨率指标上占有优势,跨孔雷达主要用于工程与环境地球物理.井间电磁成像采用更低的频率,测量复电磁信号,适合油气储集层监测,是一种地球物理前沿技术.经过在多个试验区初步试验表明,井间电磁成像是油藏研究的有效手段,可用于分析剩余油分布,寻找油气富集区,进而达到提高钻探高效井成功率和提高采收率的目的.本文详细介绍对比了这三种方法在理论和实践中的一些特点,并对未来的发展进行了展望.     

Field testing of modular borehole monitoring with simultaneous distributed acoustic sensing and geophone vertical seismic profiles at Citronelle,Alabama

A modular borehole monitoring concept has been implemented to provide a suite of well‐based monitoring tools that can be deployed cost effectively in a flexible and robust package. The initial modular borehole monitoring system was deployed as part of a CO₂ injection test operated by the Southeast Regional Carbon Sequestration Partnership near Citronelle, Alabama. The Citronelle modular monitoring system transmits electrical power and signals, fibre‐optic light pulses, and fluids between the surface and a reservoir. Additionally, a separate multi‐conductor tubing‐encapsulated line was used for borehole geophones, including a specialized clamp for casing clamping with tubing deployment. The deployment of geophones and fibre‐optic cables allowed comparison testing of distributed acoustic sensing. We designed a large source effort (>64 sweeps per source point) to test fibre‐optic vertical seismic profile and acquired data in 2013. The native measurement in the specific distributed acoustic sensing unit used (an iDAS from Silixa Ltd) is described as a localized strain rate. Following a processing flow of adaptive noise reduction and rebalancing the signal to dimensionless strain, improvement from repeated stacking of the source was observed. Conversion of the rebalanced strain signal to equivalent velocity units, via a scaling by local apparent velocity, allows quantitative comparison of distributed acoustic sensing and geophone data in units of velocity. We see a very good match of uncorrelated time series in both amplitude and phase, demonstrating that velocity‐converted distributed acoustic sensing data can be analyzed equivalent to vertical geophones. We show that distributed acoustic sensing data, when averaged over an interval comparable to typical geophone spacing, can obtain signal‐to‐noise ratios of 18 dB to 24 dB below clamped geophones, a result that is variable with noise spectral amplitude because the noise characteristics are not identical. With vertical seismic profile processing, we demonstrate the effectiveness of downgoing deconvolution from the large spatial sampling of distributed acoustic sensing data, along with improved upgoing reflection quality. We conclude that the extra source effort currently needed for tubing‐deployed distributed acoustic sensing vertical seismic profile, as part of a modular monitoring system, is well compensated by the extra spatial sampling and lower deployment cost as compared with conventional borehole geophones.     

Use of shallow groundwater temperature profiles to infer climate and land use change: interpretation and measurement challenges

Temperature is often used to infer the effect of land use and climate conditions on aquifers. Reliable data are needed to examine the temperature behaviour in the subsurface; thus, the use of robust acquisition techniques is unavoidable. Three temperature measurement techniques were applied to assess the sources of bias that could occur during temperature logging in a shallow Quaternary coastal aquifer in Ferrara (Northern Italy). Open borehole temperature logging, multilevel sampling straddle packers isolated temperature measurements within a flow cell above ground and multilevel sampling straddle packers isolated temperature measurements via an in‐well level logger (MLS‐IW) were compared for several coastal monitoring wells to gain insights on the limitations of each technique. Results show that the source of bias between the three applied techniques are different: (i) the open borehole temperature logging method tends to record heat convection through the open borehole and is not representative of the aquifer temperature distribution; (ii) the multilevel sampling straddle packers isolated temperature measurements within a flow cell above ground method is swayed by the air temperature and the heating of the submersible pump used to lift groundwater above ground; and (iii) the MLS‐IW provides the most reliable vertical thermal profiling both in summer and winter, because groundwater temperature is directly measured at the selected monitoring depth. The implementation of a 1D flow model demonstrates that if precise temperature profiles are needed to infer the influence that land use and climate changes have on groundwater, the MLS‐IW method is a reliable method that could be applied to existing monitoring wells. Copyright © 2016 John Wiley & Sons, Ltd.     

Cross-matching with interpreted warping of 3D streamer and 3D ocean-bottom-cable data at Valhall for time-lapse assessment

Legacy streamer data and newer 3D ocean‐bottom‐cable data are cross‐matched and analysed for time‐lapse analysis of geomechanical changes due to production in the Valhall Field. The issues relating to time‐lapse analysis using two such distinctly different data sets are addressed to provide an optimal cross‐matching workflow that includes 3D warping. Additionally an assessment of the differences between the imaging using single‐azimuth streamer and multi‐azimuth ocean‐bottom‐cable data is provided. The 3D warping utilized in the cross‐matching procedure is sensitive to acquisition and processing differences but is also found to provide valuable insight into the geometrical changes that occur in the subsurface due to production. As such, this work also provides a demonstration of the use of high‐resolution 3D interpreted warping to resolve the 3D heterogeneity of the compaction and subsidence. This is an important tool for Valhall, and possibly other fields, where compaction and subsidence (and monitoring thereof) are key factors in the reservoir management since the predominant observed production‐induced changes are compaction of the soft, high‐porosity chalk reservoir, due to pore‐pressure reduction, and the resultant overburden subsidence. Such reservoir compaction could have significant implications for production by changing permeabilities and production rates. Furthermore the subsidence effects could impact upon subsea installations and well‐bore stability. Geomechanical studies that have previously been used to model such subsidence and compaction are only constrained by observed surface displacements and measured reservoir pressure changes, with the geological overburden being largely neglected. The approaches suggested herein provide the potential for monitoring and assessment in three dimensions, including the probable heterogeneity and shearing, that is needed for full understanding of reservoir compaction and the resultant effects on the overburden to, for example, mitigate well‐bore failures.     

An approach to combined rock physics and seismic modelling of fluid substitution effects

The aim of seismic reservoir monitoring is to map the spatial and temporal distributions and contact interfaces of various hydrocarbon fluids and water within a reservoir rock. During the production of hydrocarbons, the fluids produced are generally displaced by an injection fluid. We discuss possible seismic effects which may occur when the pore volume contains two or more fluids. In particular, we investigate the effect of immiscible pore fluids, i.e. when the pore fluids occupy different parts of the pore volume. The modelling of seismic velocities is performed using a differential effective‐medium theory in which the various pore fluids are allowed to occupy the pore space in different ways. The P‐wave velocity is seen to depend strongly on the bulk modulus of the pore fluids in the most compliant (low aspect ratio) pores. Various scenarios of the microscopic fluid distribution across a gas–oil contact (GOC) zone have been designed, and the corresponding seismic properties modelled. Such GOC transition zones generally give diffuse reflection regions instead of the typical distinct GOC interface. Hence, such transition zones generally should be modelled by finite‐difference or finite‐element techniques. We have combined rock physics modelling and seismic modelling to simulate the seismic responses of some gas–oil zones, applying various fluid‐distribution models. The seismic responses may vary both in the reflection time, amplitude and phase characteristics. Our results indicate that when performing a reservoir monitoring experiment, erroneous conclusions about a GOC movement may be drawn if the microscopic fluid‐distribution effects are neglected.     

Monitoring Well Completion Evaluation with Borehole Geophysical Density Logging

Grout continuity and the location of the bentonite seal and sand pack in PVC-cased monitoring wells can be evaluated with cased-hole geophysical density logs. This method relies upon density contrasts among various completion conditions and annular materials. Notably, the lack of annular material behind pipe (i.e., void space) creates a low-density zone that is readily detected by borehole density measurements.
Acoustic cement bond logging has typically been applied to the evaluation of cement in the annular space of completed oil and gas production wells, and in some cases to ground water monitoring wells. These logs, however, can only be obtained in the fluid-filled portion of the borehole, and their interpretation is severely hindered by the presence of the micro-annulus between casing and cement. The influence of the micro-annulus on cement bond logs can be mitigated in steel-cased wells by pressurizing the wellbore during acquisition of the log, but this procedure is not feasible in PVC-cased monitoring wells. The micro-annulus does not affect cased-hole density logs or their interpretation.
Empirical measurements made in the laboratory with density probes provide information on their depths of investigation and response to specific completion conditions. These empirical data, and general knowledge of the density of annular completion materials (sand, bentonite, cement), are used to support interpretations of cased-hole density logs acquired in the field. Three field examples demonstrate the applicability of geophysical density logs to the evaluation of PVC-cased monitoring well completions.     

稠油蒸汽热采区声波资料异常现象的物理解释及应用

针对稠油蒸汽热采区常见的声波资料异常现象, 根据双相多孔介质声波传播理论及相关实验结果,对于这一特殊的声波测井响应特征进行了解释,认为注入蒸汽的影响导致了纵波速度的低异常及幅度的强衰减, 而使声波测井资料显现出异常高时差值或出现“跳变”现象.据此总结了利用声波资料评价蒸汽波及范围与蒸汽前缘的解释方法,并进行了多井评价实验, 取得了满意结果.同时,也为利用孔隙介质弹性波动理论评价地下蒸汽分布范围的适用性提供了新的现场实际例证.     

Gravimetric monitoring of the first field‐wide steam injection in a fractured carbonate field in Oman – a feasibility study

Gas‐Oil Gravity Drainage is to be enhanced by steam injection in a highly fractured, low permeability carbonate field in Oman. Following a successful pilot, field‐wide steam injection is being implemented, first of this type in the world. A dedicated monitoring program has been designed to track changes in the reservoir. Various observations are to be acquired, including, surface deformation, temperature measurements, microseismic, well logs, pressure and saturation measurements to monitor the reservoir. Because significant changes in the reservoir density are expected, time‐lapse gravimetry is also being considered. In this paper we investigate the feasibility of gravimetric monitoring of the thermally enhanced gravity drainage process at the carbonate field in Oman. For this purpose, forward gravity modelling is performed. Based on field groundwater measurements, the estimates of the hydrological signal are considered and it is investigated under what conditions the groundwater influences can be minimized. Using regularized inversion of synthetic gravity data, we analyse the achievable accuracy of heat‐front position estimates. In case of large groundwater variations at the field, the gravity observations can be significantly affected and, consequently, the accuracy of heat‐front monitoring can be deteriorated. We show that, by applying gravity corrections based on local observations of groundwater, the hydrological influences can to a large extent be reduced and the accuracy of estimates can be improved. We conclude that gravimetric monitoring of the heat‐front evolution has a great potential.     

3D imaging of a reservoir analogue in point bar deposits in the Ferron Sandstone, Utah, using ground-penetrating radar

Most existing reservoir models are based on 2D outcrop studies; 3D aspects are inferred from correlation between wells, and so are inadequately constrained for reservoir simulations. To overcome these deficiencies, we have initiated a multidimensional characterization of reservoir analogues in the Cretaceous Ferron Sandstone in Utah. Detailed sedimentary facies maps of cliff faces define the geometry and distribution of reservoir flow units, barriers and baffles at the outcrop. High‐resolution 2D and 3D ground‐penetrating radar (GPR) images extend these reservoir characteristics into 3D to allow the development of realistic 3D reservoir models. Models use geometric information from mapping and the GPR data, combined with petrophysical data from surface and cliff‐face outcrops, and laboratory analyses of outcrop and core samples. The site of the field work is Corbula Gulch, on the western flank of the San Rafael Swell, in east‐central Utah. The outcrop consists of an 8–17 m thick sandstone body which contains various sedimentary structures, such as cross‐bedding, inclined stratification and erosional surfaces, which range in scale from less than a metre to hundreds of metres. 3D depth migration of the common‐offset GPR data produces data volumes within which the inclined surfaces and erosional surfaces are visible. Correlation between fluid permeability, clay content, instantaneous frequency and instantaneous amplitude of the GPR data provides estimates of the 3D distribution of fluid permeability and clay content.     

Geothermal Waste Heat Utilization from In Situ Thermal Bitumen Recovery Operations

In situ thermal methods for bitumen extraction introduce a tremendous amount of energy into the reservoirs raising ambient temperatures of 13 °C to as high as 200 °C at the steam chamber edge and 50 °C along the reservoir edge. In essence these operations have unintentionally acted as underground thermal energy storage systems which can be recovered after completion of bitumen extraction activities. Groundwater flow and heat transport models of the Cold Lake, Alberta, reservoir, coupled with a borehole heat exchanger (BHE) model, allowed for investigating the use of closed‐loop geothermal systems for energy recovery. Three types of BHEs (single U‐tube, double U‐tube, coaxial) were tested and analyzed by comparing outlet temperatures and corresponding heat extraction rates. Initial one year continuous operation simulations show that the double U‐tube configuration had the best performance producing an average temperature difference of 5.7 °C, and an average heat extraction of 41 W/m. Given the top of the reservoir is at a depth of 400 m, polyethylene piping provided for larger extraction gains over more thermally conductive steel piping. Thirty year operation simulations illustrate that allowing 6 month cyclic recovery periods only increases the loop temperature gain by a factor of 1.2 over continuous operation. Due to the wide spacing of existing boreholes and reservoir depth, only a small fraction of the energy is efficiently recovered. Drilling additional boreholes between existing wells would increase energy extraction. In areas with shallower bitumen deposits such as the Athabasca region, i.e. 65 to 115 m deep, BHE efficiencies should be larger.     

Geophysical monitoring and evaluation of coastal plain aquifers

We use time domain electromagnetic (TDEM) soundings to monitor ground water conditions beneath the coastal plain in eastern North Carolina. The TDEM method measures the earth's response to an induced electromagnetic field. The resulting signal is converted, through a complex inversion process, to apparent resistivity values, which can be directly correlated to borehole resistivity logs. TDEM soundings are used to map the interface between fresh and salt water within coastal aquifers, and estimate depth to basement when siting new monitoring wells. Focused TDEM surveys have identified areas of salt water encroachment caused by high volumes of discharge from local supply wells. Electromagnetic sounding, when used in tandem with the state's network of monitoring wells, is an accurate and inexpensive tool for evaluating fresh water/salt water relationships on both local and regional scales within coastal plain aquifers.     

Successful sidetracking of a well onshore Germany by integration of 3D vertical seismic profiling technology – a case study

The exploration for and exploitation of deep Lower Rotliegend gasfields onshore in North Germany often suffers from poor surface seismic imaging. This is owing to the depth of the reservoirs and a thick and complex Zechstein salt overburden. RWE Dea conducted a 3D vertical seismic profile (VSP) survey in a low‐performing production well after the borehole was plugged near total depth. Our main objective was to improve the seismic image of the reservoir zone in the vicinity of the well to determine a new landing point for a planned sidetrack. Because acquisition was in a densely populated and also partially environmentally protected area, there were surface restrictions concerning source deployment. Additionally, due to the complex geological setting, we conducted two 2D VSP field tests and thorough pre‐survey modelling to achieve the best results in terms of seismic imaging, environmental impact and reasonable cost. Deformation bands in the drill core suggest that the initial well was drilled close to a major fault, which was regarded as the main reason for the disappointing production rate. Therefore, we put special emphasis on fault detection in our processing and interpretation. Our interpretation approach used an enhanced structural mapping workflow that helped to design a sidetrack. When the sidetrack was drilled two years later, it ended up being one of the most productive wells in the field.