Characterisation of a highly heterogeneous geothermal reservoir based on geophysical well logs

2021 ◽  
Author(s):  
Johanna Bauer ◽  
Daniela Pfrang ◽  
Michael Krumbholz
Keyword(s):  
Reservoir Characterization ◽  
Sustainable Use ◽  
District Heating ◽  
Upper Jurassic ◽  
Geothermal Reservoir ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Geophysical Logging ◽  
Matrix Permeability ◽  
Geophysical Well Logs

<p>For successful exploitation of geothermal reservoirs, temperature and transmissibility are key factors. The Molasse Basin in Germany is a region in which these requirements are frequently fulfilled. In particular, the Upper Jurassic Malm aquifer, which benefits from high permeability due to locally intense karstification, hosts a large number of successful geothermal projects. Most of these are located close to Munich and the “Stadtwerke München (SWM)” intends to use this potential to generate most of the district heating demands from geothermal plants by 2040.</p><p>We use geophysical logging data and sidewall cores to analyse the spatial distribution of reservoir properties that determine porosity, permeability, and temperature distribution. The data are derived from six deviated wells drilled from one well site. The reservoir rocks are separated by faults and lie in three different tectonic blocks. The datasets include image logs, GR, sonic velocities, temperature, flowmeter- and mud logs. We not only focus on correlations between rock porosity and matrix permeability, but also on how permeability provided by fractures and karstification correlate with inflow zones and reservoir temperature. In addition, we correlate individual parameters with respect to their lithology, dolomitisation and the rock’s image fabric type, adapted from Steiner and Böhm (2011).  </p><p>Our results show that fracture intensity and orientations vary strongly, between and within individual wells. However, we observed local trends between fracture systems and rock properties. For instance fracture intensities and v<sub>p</sub> velocities (implying lower porosities) are higher in rock sections classified as dolomites without bedding contacts. As these homogeneous-appearing dolomites increase, from N to S, the mean fracture intensities and v<sub>p</sub> velocities also increase. Furthermore, we observed most frequently substantial karstification in dolomites and dolomitic limestones. Nevertheless, an opposing trend for the percentage of substantial karstification can be also found, i.e., the amount of massive karstification is higher in the northern wells. The interpretation of flowmeter measurements show that the main inflow zones concentrate in those Upper Malm sections that are characterised by karstification and/or intense fracturing.</p><p>In the next step, we will correlate laboratory measurements of outcrop- and reservoir samples (e.g. porosity, permeability, and mechanical rock properties) with the logging data. The aim is to test the degree to which analogue samples can contribute to reservoir characterization in the Upper Jurassic Malm Aquifer (Bauer et al., 2017).</p><p>This work is carried out in the research project REgine "Geophysical-geological based reservoir engineering for deep-seated carbonates" and is financed by the German Federal Ministry for Economic Affairs and Energy (FKZ: 0324332B).</p><p>Bauer, J. F., Krumbholz, M., Meier, S., and Tanner, D. C.: Predictability of properties of a fractured geothermal reservoir: The opportunities and limitations of an outcrop analogue study, Geothermal Energy, 5, 24, https://doi.org/10.1186/s40517-017-0081-0, 2017.</p><p>Steiner, U., Böhm, F.: Lithofacies and Structure in Imagelogs of Carbonates and their Reservoir Implications in Southern Germany. Extended Abstract 1st Sustainable Earth Sciences Conference & Exhibition – Technologies for Sustainable Use of the Deep Sub-surface, Valencia, Spain, 8-11 November, 2011.</p>

Factors Controlling Porosity Permeability Relationship for Reservoir Quality Prediction: A Case Study of Malay Basin Reservoir, Malaysia

2021 ◽  
Author(s):  
Fadzlin Hasani Kasim ◽  
Budi Priyatna Kantaatmadja ◽  
Wan Nur Wan M Zainudin ◽  
Amita Ali ◽  
Hasnol Hady Ismail ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Visual Analysis ◽  
Mineral Dissolution ◽  
Rock Properties ◽  
Reservoir Quality ◽  
Hydrocarbon Potential ◽  
Lower Grade ◽  
Reservoir Properties ◽  
Reservoir Evaluation ◽  
Porosity And Permeability

Abstract Predicting the spatial distribution of rock properties is the key to a successful reservoir evaluation for hydrocarbon potential. However, a reservoir with a complex environmental setting (e.g. shallow marine) becomes more challenging to be characterized due to variations of clay, grain size, compaction, cementation, and other diagenetic effects. The assumption of increasing permeability value with an increase of porosity may not be always the case in such an environment. This study aims to investigate factors controlling the porosity and permeability relationships at Lower J Reservoir of J20, J25, and J30, Malay Basin. Porosity permeability values from routine core analysis were plotted accordingly in four different sets which are: lithofacies based, stratigraphic members based, quartz volume-based, and grain-sized based, to investigate the trend in relating porosity and permeability distribution. Based on petrographical studies, the effect of grain sorting, mineral type, and diagenetic event on reservoir properties was investigated and characterized. The clay type and its morphology were analyzed using X-ray Diffractometer (XRD) and Spectral electron microscopy. Results from porosity and permeability cross-plot show that lithofacies type play a significant control on reservoir quality. It shows that most of the S1 and S2 located at top of the plot while lower grade lithofacies of S41, S42, and S43 distributed at the middle and lower zone of the plot. However, there are certain points of best and lower quality lithofacies not located in the theoretical area. The detailed analysis of petrographic studies shows that the diagenetic effect of cementation and clay coating destroys porosity while mineral dissolution improved porosity. A porosity permeability plot based on stratigraphic members showed that J20 points located at the top indicating less compaction effect to reservoir properties. J25 and J30 points were observed randomly distributed located at the middle and bottom zone suggesting that compaction has less effect on both J25 and J30 sands. Lithofacies description that was done by visual analysis through cores only may not correlate-able with rock properties. This is possibly due to the diagenetic effect which controls porosity and permeability cannot visually be seen at the core. By incorporating petrographical analysis results, the relationship between porosity, permeability, and lithofacies can be further improved for better reservoir characterization. The study might change the conventional concept that lower quality lithofacies does not have economic hydrocarbon potential and unlock more hydrocarbon-bearing reserves especially in these types of environmental settings.

scholarly journals Estimation of reservoir properties from seismic data by smooth neural networks

Geophysics ◽  
2003 ◽  
Vol 68 (6) ◽  
pp. 1969-1983 ◽  
Author(s):  
M. M. Saggaf ◽  
M. Nafi Toksöz ◽  
H. M. Mustafa
Keyword(s):  
Seismic Data ◽  
Reservoir Characterization ◽  
Back Propagation ◽  
Reservoir Rock ◽  
Seismic Survey ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Network Parameters ◽  
Generalization Problem ◽  
Validation Tests

The performance of traditional back‐propagation networks for reservoir characterization in production settings has been inconsistent due to their nonmonotonous generalization, which necessitates extensive tweaking of their parameters in order to achieve satisfactory results and avoid overfitting the data. This makes the accuracy of these networks sensitive to the selection of the network parameters. We present an approach to estimate the reservoir rock properties from seismic data through the use of regularized back propagation networks that have inherent smoothness characteristics. This approach alleviates the nonmonotonous generalization problem associated with traditional networks and helps to avoid overfitting the data. We apply the approach to a 3D seismic survey in the Shedgum area of Ghawar field, Saudi Arabia, to estimate the reservoir porosity distribution of the Arab‐D zone, and we contrast the accuracy of our approach with that of traditional back‐propagation networks through cross‐validation tests. The results of these tests indicate that the accuracy of our approach remains consistent as the network parameters are varied, whereas that of the traditional network deteriorates as soon as deviations from the optimal parameters occur. The approach we present thus leads to more robust estimates of the reservoir properties and requires little or no tweaking of the network parameters to achieve optimal results.

scholarly journals Permeability and Mineralogy of the Újfalu Formation, Hungary, from Production Tests and Experimental Rock Characterization: Implications for Geothermal Heat Projects

Energies ◽  
2021 ◽  
Vol 14 (14) ◽  
pp. 4332
Author(s):  
Cees J. L. Willems ◽  
Chaojie Cheng ◽  
Sean M. Watson ◽  
James Minto ◽  
Aislinn Williams ◽  
...  
Keyword(s):  
Reservoir Characterization ◽  
Pannonian Basin ◽  
Flow Simulation ◽  
District Heating ◽  
Ct Scanning ◽  
Xrd Analysis ◽  
Reservoir Rock ◽  
Reservoir Properties ◽  
Geothermal Heat ◽  
Rock Characterization

Hundreds of geothermal wells have been drilled in Hungary to exploit Pannonian Basin sandstones for district heating, agriculture, and industrial heating projects. Most of these sites suffer from reinjection issues, limiting efficient use of this vast geothermal resource and imposing significant extra costs for the required frequent workovers and maintenance. To better understand the cause of this issue requires details of reservoir rock porosity, permeability, and mineralogy. However, publicly available data for the properties of reservoir rocks at geothermal project sites in Hungary is typically very limited, because these projects often omit or limit data acquisition. Many hydrocarbon wells in the same rocks are more extensively documented, but their core, log, or production data are typically decades old and unavailable in the public domain. Furthermore, because many Pannonian sandstone formations are poorly consolidated, coring was always limited and the collected core often unsuitable for conventional analysis, only small remnant fragments typically being available from legacy hydrocarbon wells. This study aims to reduce this data gap and to showcase methods to derive reservoir properties without using core for flow experiments. The methods are thin-section analysis, XRD analysis and mercury intrusion porosimetry, and X-CT scanning followed by numerical flow simulation. We validate our results using permeability data from conventional production testing, demonstrating the effectiveness of our method for detailed reservoir characterization and to better constrain the lateral variation in reservoir properties across the Pannonian Basin. By eliminating the need for expensive bespoke coring to obtain reservoir properties, such analysis will contribute to reducing the capital cost of developing geothermal energy projects, thus facilitating decarbonization of global energy supply.

Synthetic core from conventional logs: A new method of interpretation for identification of key reservoir properties

2015 ◽  
Vol 3 (1) ◽  
pp. SA1-SA14 ◽  
Author(s):  
Mahbub Alam ◽  
Latif Ibna-Hamid ◽  
Joan Embleton ◽  
Larry Lines
Keyword(s):  
Reservoir Simulation ◽  
Reservoir Characterization ◽  
Gamma Ray ◽  
Laboratory Data ◽  
Sedimentary Facies ◽  
Rock Properties ◽  
Reservoir Properties ◽  
Particle Volume ◽  
Single Curve ◽  
Conventional Logs

We developed a unique method to generate reservoir attributes by creating an artificial core for those wells that have no core, but that have gamma, neutron, and density logs. We examined sedimentary facies distributions, reservoir attributes, and mechanical parameters of the rock for noncored wells to increase the data density and improve the understanding of the reservoir. This method eventually helps to improve high-resolution 3D geocellular models, geomechanical models, and reservoir simulation in reservoir characterization. Artificial or synthetic cores are created using a single curve that builds facies templates using the information from the cores of nearby offset wells, which belong to the same depositional environment. The single curve, called the fine particle volume (FPV), is the average of two shale volumes calculated from the gamma-ray log and from a combination of neutron and density logs. Using facies templates, the FPV curve builds the synthetic core for geocellular modeling and reservoir simulation, and it represents the sedimentary facies distribution in the well with all the reservoir attributes obtained from laboratory data of the original core. The vertical succession of the synthetic core has the characteristics of actual sedimentary facies with reservoir attributes such as porosity, permeability, and other rock properties. The result of creating the synthetic core was validated visually and statistically with the actual cores, and each of the cored wells was considered as a noncored well. The limitation of this method is associated with the accuracy of the logging data acquisition, normalization factors, and facies template selection criteria.

scholarly journals Upgrading a District Heating System by Means of the Integration of Modular Heat Pumps, Geothermal Waters, and PVs for Resilient and Sustainable Urban Energy

Energies ◽  
2021 ◽  
Vol 14 (9) ◽  
pp. 2347
Author(s):  
Elżbieta Hałaj ◽  
Jarosław Kotyza ◽  
Marek Hajto ◽  
Grzegorz Pełka ◽  
Wojciech Luboń ◽  
...  
Keyword(s):  
District Heating ◽  
Heating System ◽  
Upper Jurassic ◽  
Heat Pumps ◽  
Water Levels ◽  
Energy Potential ◽  
Geothermal Waters ◽  
District Heating System ◽  
Heating And Cooling ◽  
The City

Krakow has an extensive district heating network, which is approximately 900 km long. It is the second largest city in terms of the number of inhabitants in Poland, resulting in a high demand for energy—for both heating and cooling. The district heating of the city is based on coal. The paper presents the conception of using the available renewable sources to integrate them into the city’s heating system, increasing the flexibility of the system and its decentralization. An innovative solution of the use of hybrid, modular heat pumps with power dependent on the needs of customers in a given location and combining them with geothermal waters and photovoltaics is presented. The potential of deep geothermal waters is based on two reservoirs built of carbonate rocks, namely Devonian and Upper Jurassic, which mainly consist of dolomite and limestone. The theoretical potential of water intake equal to the nominal heating capacity of a geothermal installation is estimated at 3.3 and 2.0 MW, respectively. Shallow geothermal energy potential varies within the city, reflecting the complex geological structure of the city. Apart from typical borehole heat exchangers (BHEs), the shallower water levels may represent a significant potential source for both heating and cooling by means of water heat pumps. For the heating network, it has been proposed to use modular heat pumps with hybrid sources, which will allow for the flexible development of the network in places previously unavailable or unprofitable. In the case of balancing production and demand, a photovoltaic installation can be an effective and sufficient source of electricity that will cover the annual electricity demand generated by the heat pump installation, when it is used for both heating and cooling. The alternating demand of facilities for heating and cooling energy, caused by changes in the seasons, suggests potential for using seasonal cold and heat storage.

scholarly journals Chemical and stable isotope composition of surface and groundwater in the surroundings of the Los Humeros Caldera, Puebla, Mexico

2019 ◽  
Vol 98 ◽  
pp. 07013
Author(s):  
Thomas Kretzschmar ◽  
Matteo Lelli ◽  
Ruth Alfaro ◽  
Juan Ignacio Sanchez ◽  
Yann Rene Ramos
Keyword(s):  
Stable Isotope ◽  
Isotope Composition ◽  
Regression Line ◽  
Sustainable Use ◽  
Geothermal Reservoir ◽  
Maximum Temperature ◽  
Stable Isotope Composition ◽  
Local Fracture ◽  
Hydrogeological Model ◽  
Fracture Systems

It is important to develop a regional hydrogeological model to identify possible recharge and discharge areas for a sustainable use of a geothermal reservoir. The Los Humeros geothermal area is situated within five surficial watersheds and coveres an area of more than 15.000 km2. A total of 208 well and spring samples were collected between June 2017 and November 2018. The stable isotope data for this region define a regression line of δDH2O = 8.032·δ18O + 12 and indicate that groundwater is recharged by regional precipitation. At least 39 groundwater wells, with a maximum temperature of 35 °C, show temperatures above the reported mean average surface temperature of 15 °C. Characteristic elements for geothermal reservoir fluids (B, Li, As) are also present in these groundwaters, indicating a possible connection between the reservoir fluid and the local groundwater through local fracture systems. Concentration of B in these hot wells is between 150 and 35000 ppb.

Latest developments in seismic texture analysis for subsurface structure, facies, and reservoir characterization: A review

Geophysics ◽  
2011 ◽  
Vol 76 (2) ◽  
pp. W1-W13 ◽  
Author(s):  
Dengliang Gao
Keyword(s):  
Texture Analysis ◽  
Reservoir Characterization ◽  
Preliminary Test ◽  
Seismic Facies ◽  
Least Squares Regression ◽  
Reservoir Properties ◽  
Seismic Amplitude ◽  
Texture Model ◽  
Facies Classification ◽  
Analysis Window

In exploration geology and geophysics, seismic texture is still a developing concept that has not been sufficiently known, although quite a number of different algorithms have been published in the literature. This paper provides a review of the seismic texture concepts and methodologies, focusing on latest developments in seismic amplitude texture analysis, with particular reference to the gray level co-occurrence matrix (GLCM) and the texture model regression (TMR) methods. The GLCM method evaluates spatial arrangements of amplitude samples within an analysis window using a matrix (a two-dimensional histogram) of amplitude co-occurrence. The matrix is then transformed into a suite of texture attributes, such as homogeneity, contrast, and randomness, which provide the basis for seismic facies classification. The TMR method uses a texture model as reference to discriminate among seismic features based on a linear, least-squares regression analysis between the model and the data within an analysis window. By implementing customized texture model schemes, the TMR algorithm has the flexibility to characterize subsurface geology for different purposes. A texture model with a constant phase is effective at enhancing the visibility of seismic structural fabrics, a texture model with a variable phase is helpful for visualizing seismic facies, and a texture model with variable amplitude, frequency, and size is instrumental in calibrating seismic to reservoir properties. Preliminary test case studies in the very recent past have indicated that the latest developments in seismic texture analysis have added to the existing amplitude interpretation theories and methodologies. These and future developments in seismic texture theory and methodologies will hopefully lead to a better understanding of the geologic implications of the seismic texture concept and to an improved geologic interpretation of reflection seismic amplitude.

The Clipper Field, Blocks 48/19a, 48/19c, UK North Sea

2003 ◽  
Vol 20 (1) ◽  
pp. 691-698
Author(s):  
M. J. Sarginson
Keyword(s):  
North Sea ◽  
Upper Permian ◽  
Lower Permian ◽  
Reservoir Properties ◽  
Gas Field ◽  
Field Development ◽  
Matrix Permeability ◽  
Recoverable Reserves ◽  
Reservoir Permeability ◽  
Sandstone Formation

AbstractThe Clipper Gas Field is a moderate-sized faulted anticlinal trap located in Blocks 48/19a, 48/19c and 48/20a within the Sole Pit area of the southern North Sea Gas Basin. The reservoir is formed by the Lower Permian Leman Sandstone Formation, lying between truncated Westphalian Coal Measures and the Upper Permian evaporitic Zechstein Group which form source and seal respectively. Reservoir permeability is very low, mainly as a result of compaction and diagenesis which accompanied deep burial of the Sole Pit Trough, a sub basin within the main gas basin. The Leman Sandstone Formation is on average about 715 ft thick, laterally heterogeneous and zoned vertically with the best reservoir properties located in the middle of the formation. Porosity is fair with a field average of 11.1%. Matrix permeability, however, is less than one millidarcy on average. Well productivity depends on intersecting open natural fractures or permeable streaks within aeolian dune slipface sandstones. Field development started in 1988. 24 development wells have been drilled to date. Expected recoverable reserves are 753 BCF.

Integrated reservoir characterization: Beyond tomography

Geophysics ◽  
1995 ◽  
Vol 60 (2) ◽  
pp. 354-364 ◽  
Author(s):  
Larry Lines ◽  
Henry Tan ◽  
Sven Treitel ◽  
John Beck ◽  
Richard Chambers ◽  
...  
Keyword(s):  
History Matching ◽  
Preferential Flow ◽  
Reservoir Characterization ◽  
Seismic Anisotropy ◽  
Flow Direction ◽  
Geophysical Methods ◽  
Reservoir Properties ◽  
Traveltime Tomography ◽  
Sonic Log ◽  
Primary Water

In 1992, there was a collaborative effort in reservoir geophysics involving Amoco, Conoco, Schlumberger, and Stanford University in an attempt to delineate variations in reservoir properties of the Grayburg unit in a West Texas [Formula: see text] pilot at North Cowden Field. Our objective was to go beyond traveltime tomography in characterizing reservoir heterogeneity and flow anisotropy. This effort involved a comprehensive set of measurements to do traveltime tomography, to image reflectors, to analyze channel waves for reservoir continuity, to study shear‐wave splitting for borehole stress‐pattern estimation, and to do seismic anisotropy analysis. All these studies were combined with 3-D surface seismic data and with sonic log interpretation. The results are to be validated in the future with cores and engineering data by history matching of primary, water, and [Formula: see text] injection performance. The implementation of these procedures should provide critical information on reservoir heterogeneities and preferential flow direction. Geophysical methods generally indicated a continuous reservoir zone between wells.

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