Wellbore Reservoir Research Articles

Development of a new reagent for the prevention of asphaltene-resin-paraffin deposits

Asphaltene-Resin-Paraffin deposits (ARPD) form a certain proportion of the crude oil mass, separating as temperature and pressure decrease and adsorbing to the surfaces of the reservoir wellbore zone, downhole equipment and tubulars. These deposits precipitate in the wellbore zone, oilfield equipment and pipes,resulting in reduced system productivity, reduced pumping efficiency of the pumping equipment and other negative consequences. Asphalt-resin and paraffin deposits (ARPD) are a complex mixture of solid paraffin hydrocarbons, asphalt-resin substances (ARS), water and mechanical impurities. The strength and composition of ARPD depend on the composition and properties of oil, geological, physical and technological conditions of field development. Chemical methods for removing deposits are currently the most widely used, as they are highly effective and technologically advanced. To this end, new reagents have been developed and their physico-chemical properties have been studied. Subsequently, the selected reagents were tested on oil samples from Oil and Gas Production Department (OGPD) with a paraffin content of more than 6 %. It was also shown that paraffin inhibitors have individual effects; a reagent that is effective on oil from one field may not have the same effect on oil from other fields. The research includes studies of selected reagents for paraffinic oils from different fields. Using the «cold finger» method, the efficacy of the selected reagents against paraffin deposition was investigated and their optimum doses were determined. Keywords: reagent; sendiment; paraffin; asphaltene; resin; well bottom zone; viscosity; depressor.

The Feasibility of Heat Extraction Using CO2 in the Carbonate Reservoir in Shandong Province, China

CO2 is being considered as an effective alternative working fluid for geothermal applications due to its superior fluid dynamics and heat transfer properties compared to water. Utilizing sedimentary rocks for geothermal energy recovery through a CO2-plume geothermal system, especially in carbonate reservoirs, has been shown to be a practical approach that eliminates the need for hydraulic fracturing. However, uncertainties remain regarding the thermal and hydraulic behavior, particularly the chemical interactions between CO2 and carbonate rocks. This study develops a comprehensive wellbore–reservoir coupling reactive transport model based on specific information obtained from the Ordovician limestone geothermal reservoir in Shandong, China. The model aims to assess the feasibility of heat extraction in carbonate reservoirs by evaluating the heat extraction performance and fluid–rock interaction. The results indicate a rapid temperature drop after CO2 breakthrough due to the Joule–Thomson effect. Simultaneously, the fluid transitions into and maintains a two-phase state throughout the operation. Chemical reactions within the reservoir are not aggressive since complete mixing between unsaturated water and CO2 only occurs in the vicinity of the production well, highlighting the potential of utilizing carbonate reservoirs for efficient heat extraction in geothermal systems. Further research is needed to optimize the performance of CO2-based geothermal systems in carbonate reservoirs.

Study on Predicting Liquid Production Profile in Horizontal Wells Considering the Mechanism of Annular Flow Resistance and Water Control

The coated particle ICD water control technology has been widely used in horizontal well completion in offshore oil fields in recent years, but there is a lack of research on the simulation and prediction methods for liquid production profiles. By analyzing the dynamic inflow process of fluid, starting from the laws of momentum conservation and mass conservation, a coupled mathematical model of horizontal well reservoir wellbore pressure drop considering the mechanism of annular flow resistance was established, and solved through programming. Based on the actual well data of a certain block in an offshore oilfield, a horizontal well reservoir production model was established. The calculation results of the example show that the annular flow resistance and water control technology can effectively control the balanced liquid production of horizontal wells, thereby increasing the anhydrous oil recovery period and improving the oil recovery rate of the oilfield; The coupling model simulation and prediction method can fully reflect the mutual influence between the oil reservoir, wellbore annulus, ICD, and horizontal wellbore; The effective diameter of the ICD valve affects the changes in oil production and water content. The placement of the ICD well section has a significant effect on water control, and the compactness of the filled particles has a certain impact on pressure and water content changes.

Prediction of Self‐Flow Production in Segmented Hydraulic Fractured Horizontal Shale Wells Based on EDFM

Terrestrial shale oil resources in China are abundant. However, its development in China is still in the early stages. And its scale of transformation and production systems is still being explored. Currently, reservoir numerical simulation on shale oil reservoirs faces two main challenges: (1) multiscale flow of matrix–microfracture–hydraulic fractures in shale oil reservoirs and (2) bidirectional coupling of reservoir–wellbore–nozzle systems. This paper proposes a self‐flow model for horizontal shale wells that describes multiscale fractures and production controlled by the nozzle. The model integrates the embedded discrete fracture model (EDFM), pipe flow model, and nozzle flow model. The accuracy of the model has been validated through comparisons with other reference models and field data. Then, this study analyzes the effects of different natural fracture densities, horizontal section lengths, number of fracturing stages, and nozzle diameters on the production capacity during the self‐flow period. The results indicate that reservoirs with developed natural fractures can enhance the development efficiency during the self‐flow period, and appropriate horizontal section lengths and fracturing stages contribute to achieving maximum economic benefits in development. Additionally, smaller nozzle diameters lead to longer self‐flow periods and higher cumulative production. The research findings of this paper can be applied to simulate the production of hydraulic fractured horizontal shale wells.

New Insight to Interlayer Interference During Three-Gas Co-production Based on a Wellbore–Reservoir Coupling Model

New Insight to Interlayer Interference During Three-Gas Co-production Based on a Wellbore–Reservoir Coupling Model

Pressure transient behaviors for horizontal wells with well interferences, complex fractures and two-phase flow

During the production of multi-stage, multi-well pads in shale reservoirs, there are common phenomena of well interferences, complex fracture generation, and multi-phase flow for the multi-well pad. However, there still lacks an understanding on the pressure transient behaviors with those phenomena. To narrow this gap, the pressure transient behaviors of oil-water two-phase flow of fractured horizontal wells with complex fractures and well interferences are studied by a numerical pad-well model, based on PEBI grids and discrete fracture model (DFM).The pressure transient solutions of fractured horizontal wells with complex fractures and well interferences have been demonstrated by model verifications and field applications. The results show that the flow regime of interference effects is stronger when the child well has a larger production rate, a smaller well spacing, more secondary fractures, longer secondary fractures, and higher fracture conductivity. It is also found that the formation pressure loss increases with increasing oil phase viscosity and oil volume factor when the viscosity of water is constant. The oil/water volume factor mainly affect the well testing interpretation of parameters such as wellbore reservoir coefficient. What's more, the field application shows that the well testing data are interpreted and the fracture parameters are evaluated successfully with well interferences, while the single-well testing model without considering well interference cannot match with field data at the late stage and the estimation errors will occur. This work is meaningful to understand the well interference and to evaluate the fracture parameters in multi-stage, multi-well pad with multi-phase flow.

Research and Application of Shale Gas Reservoir-Wellbore Integrated Model Coupling Method

As a representative of emerging unconventional energy, shale gas has the characteristics of large reserves, long production cycle, and environmental protection. However, due to the complex geological characteristics of shale gas reservoirs, the economic development of shale gas reservoirs is difficult. In this paper, on the basis of a full investigation of relevant literature, according to the permeability mechanism of shale gas reservoirs, the productivity of horizontal wells in low-permeability gas reservoirs is studied, and an integrated dynamic simulation model of gas reservoir wellbore is established. And the historical fitting and dynamic forecasting are carried out, and the results are in good agreement with the actual situation.

Application of a biomimetic wellbore stabilizer with strong adhesion performance for hydrate reservoir exploitation

Natural gas hydrate (NGH) in marine is usually reserved in the pores or cracks of weakly cemented argillaceous siltstones. Moreover, the hydrates are susceptible to variations in temperature and pressure conditions when water-based drilling fluids (WBDFs) are drilled into hydrate reservoirs, leading to the hydrate in-situ decomposition and severe sand production. In this work, an inexpensive and facilely prepared biomimetic wellbore stabilizer with strong adsorption of multiple hydrogen bonds was prepared by fusing catechol-rich tannic acid (TA) and polyvinyl alcohol (PVA) with polyol hydroxyl adsorption function, referred to as TA-PVA complex (TA-PVA). TA-PVA was added to WBDFs to strengthen the NGH reservoir wellbore for ensuring the safety of drilling process in a wide temperature range (2-60℃). The microscopic characterization of TA-PVA and its cohesion mechanism with argillaceous siltstone was investigated by Fourier transform infrared spectroscopy (FTIR), transmission electron microscopy (TEM), scanning electron microscopy (SEM) and atomic force microscopy (AFM). The mechanical properties of skeleton of the artificial hydrate cores were evaluated by compressive strength test, with maximum compressive strength reaching 0.45 MPa. And the adhesion force of TA-PVA to the probe modified by silica microsphere (PSM) was further studied by AFM. Meanwhile, the adhesion forces between TA-PVA and cyclopentane hydrate particles were measured at 1.5℃. Adhesion test results demonstrate that TA-PVA can bond clay particles, quartz sand and hydrate particles together. In detail, the adhesion force between TA-PVA and PSM reaches more than 164.46 mN/m, the adhesion force between TA-PVA droplet and cyclopentane hydrate particle reaches 43.19 mN/m. The differential scanning calorimetry (DSC)curves demonstrate that TA-PVA releases no heat between 0 and 60 °C, indicating that TA-PVA has no impact on the decomposition of NGH, showing the potential to maintain the integrity of NGH reservoir.

An uncertainty quantitative model of wellbore failure risk for underground gas storage in depleted gas reservoir during the construction process

The sensitivity of wellbore-wall failure risk under depleted formation-pressure coefficients and underground gas storage in depleted gas reservoirs during the construction process is quantitatively assessed, especially the failure risk of wellbore collapse and fracture in depleted reservoirs with ultralow formation-pressure coefficients, and to effectively guide safe construction. Based on the Mohr–Coulomb failure theory and multilevel confidence model, three typical in situ stress states (normal fault, slip fault, and reverse fault) are considered to establish an analytical model for wellbore-wall failure risk under different depleted reservoir pressure coefficients. Taking a depleted sandstone reservoir as the main reservoir for wellbore-wall stability analysis as an example, a wellbore-wall stability state visualization analysis model with three typical in situ stress states under arbitrary orientations and well deviation angles is obtained, and the uncertain probability distribution law of wellbore-wall collapse and fracture failure in a reservoir with an ultralow formation-pressure coefficient is constructed using a stochastic uncertainty simulation method with interval confidence. The distribution patterns of wellbore-wall stress fields and borehole safety density windows during the construction of depleted reservoirs are quantitatively analyzed. The results show that a safety density window with interval uncertainty estimates would be more intuitive for assessing the stability of the reservoir wellbore wall in a quantitative form, and it is observed that inclined well sections in depleted reservoirs typically have narrower safety density windows. In conclusion, the lower and upper limits of the safety density window in numerical examples are 1.4 to 1.6 g/cm3 (normal fault state), 1.2 to 1.5 g/cm3 (slip fault state), and 1.2 to 1.65 g/cm3 (reverse fault state), respectively. The research results can provide effective guidance for wellbore instability control, design, and construction of directional wells in depleted gas reservoirs.

Production Performance Simulation of the Fractured Horizontal Well Considering Reservoir and Wellbore Coupled Flow in Shale Gas Reservoirs

Unmodified original shale gas reservoirs have been demonstrated to have extremely low permeability, and the long horizontal drilling and hydraulic fracturing techniques are widely used to obtain economic gas production. However, these techniques can result in a nonlinear flow of fluids during transport through the multi-scale pore system and the complex fracture network around the horizontal well, as well as a two-phase gas-water flow during shale production. To solve these issues, in this paper, first, the complex fracture network around the horizontal well is characterized using the discrete main hydraulic fractures combined with composite regions with different properties. Then, the dual porosity media and discrete-fracture model are implemented to describe the nonlinear flow behavior in the multi-scale pore system, and a wellbore pressure drop model is established to characterize the transient two-phase gas–liquid flow in the different sections of the fractured horizontal well. Finally, the coupled reservoir wellbore flow model is fully implicitly solved using the control volume finite element method and unstructured tetrahedral grids. The results of the simulation model of a multi-stage fractured horizontal well in the shale of the Longmaxi Formation will help field engineers deeply understand gas and water production performance and the dynamics of wellbore and reservoir pressure, as well as optimize development schemes.

Development of 1D-Synthetic Geomechanical Well Logs for Applications Related to Reservoir Geomechanics in Buzurgan Oil Field

Knowledge of the distribution of the rock mechanical properties along the depth of the wells is an important task for many applications related to reservoir geomechanics. Such these applications are wellbore stability analysis, hydraulic fracturing, reservoir compaction and subsidence, sand production, and fault reactivation. A major challenge with determining the rock mechanical properties is that they are not directly measured at the wellbore. They can be only sampled at well location using rock testing. Furthermore, the core analysis provides discrete data measurements for specific depth as well as it is often available only for a few wells in a field of interest. This study presents a methodology to generate synthetic-geomechanical well logs for the production section of the Buzurgan oil field, located in the south of Iraq, using an artificial neural network. An issue with the area of study is that shear wave velocities and pore pressure measurements in some wells are missing or incomplete possibly for cost and time-saving purposes. The unavailability of these data can potentially create inaccuracies in reservoir characterization n and production management. To overcome these challenges, this study presents two developed models for estimating the shear wave velocity and pore pressure using ANN techniques. The input parameters are conventional well logs including compressional wave, bulk density, and gamma-ray. Also, this study presents a construction of 1-D mechanical earth model for the production section of Buzurgan oil field which can be used for optimizing the selected mud weights with less wellbore problems (less nonproductive time. The results showed that artificial neural network is a powerful tool in determining the shear wave velocity and formation pore pressure using conventional well logs. The constructed 1D MEM revealed a high matching between the predicted wellbore instabilities and the actual wellbore failures that were observed by the caliper log. The majority of borehole enlargements can be attributed to the formation shear failures due to an inadequate selection of mud weights while drilling. Hence, this study presents optimum mud weights (1.3 to 1.35 g/cc) that can be used to drill new wells in the Buzurgan oil field with less expected drilling problems.

A MODIFIED METHOD OF SOLVING THE PRESSURE–RATE DECONVOLUTION PROBLEM FOR IDENTIFICATION OF WELLBORE–RESERVOIR SYSTEM

In the paper, the method suggested in [5] for solving the pressure–rate deconvo- lution problem was modified with implementation for the synthetic (quasi-real) oil and gas data. Modification of the method is based on using the additional a priori information on the function v(t) = tg(t) in the logarithmic scale. On the initial time interval, the function is concave and its final interval is monotone. Here, g(t) is the solution of the basis equation (1). To take into account these properties in the Tikhonov algorithm, the penalty function method is used. It allowed one to increase the precision of the numerical solution and to improve quality of identification of the wellbore–reservoir system. Numerical experiments are provided.

Coupled wellbore–reservoir heat and mass transfer model for horizontal drilling through hydrate reservoir and application in wellbore stability analysis

To address the wellbore instability risk during drilling in hydrate reservoirs, a fully coupled wellbore–reservoir model for horizontal drilling through a hydrate reservoir is presented, which considers the dynamic heat and mass transfer between the wellbore and reservoir and the coupling interactions between the fluid flow, heat transfer, and evolution of mechanical properties in hydrate-bearing sediments. A numerical method based on COMSOL Multiphysics + MATLAB was first proposed, and the accuracy of this model was verified by comparing it with experimental data and another mathematical model. The rules of heat and mass transfer between the wellbore and reservoir and the yield failure behaviors of the wellbore are thoroughly analyzed based on the data of hydrate-bearing sediments in the Shenhu area. The simulation results indicate that the temperature of the hydrate reservoir increases with the invasion of drilling fluid. The radii of the thermal disturbance zone at the toe and heel of the horizontal well are approximately 0.48 m and 0.64 m after 20 h, respectively. The formation shear strength near the wellbore gradually decreases from the initial 3.24 MPa–2.09 MPa due to hydrate decomposition; then, the formation begins to yield, and the yield ratio of the borehole reaches 92.56% after 20 h. Compared with the drilling fluid displacement and density, the inlet temperature of the drilling fluid plays an absolute leading role in the wellbore extension length. When the inlet temperature is less than 22.5 °C, the reservoir hydrate will not decompose. This work can provide a theoretical reference for the design of drilling fluids aimed at controlling borehole stability issues and for the design of the length of horizontal wells during drilling in hydrate reservoirs.

Seismic Driven Geomechanical Modeling of Uplifted and Subsided Wells in Mumbai Offshore and Its Engineering Implications

Seismic data provide evidence about hydrocarbon deposition, geological and geophysical subsurface information, including geomechanical aspects. Deriving and understanding geomechanical properties is crucial for reservoir management as it can avoid drilling and production-related problems that cause environmental impacts associated with land subsidence and uplift. The Poison's ratio (PR), Young Modulus (YM), and elastic moduli for a reservoir block were estimated using 3D seismic pre-stack data and well data. 3D Mechanical Earth Models (MEM) were also developed using the well logs, seismic horizons, and drilling data. Seismic data-derived geomechanical properties were compared with the mechanical earth models for the first time for this field. Well-tie analysis was used for inversion of 3D seismic data to extract detailed waveform and amplitude information. The brittleness index of the subsurface layers was estimated, which is a critical rock property that provides information about rock hardness and fragility phenomenon. The brittleness index has a diverse range from 5-35%, with significant contrast at shallow zones. PR and YM models generated from 3D MEM and seismic data have average values of 0.2 -0.6 and 5 - 28 GPa with significant contrast from shales and carbonates. The study recommends that the drilling through these problematic zones should be avoided to avoid wellbore problems that cause challenges in maintaining wellbore integrity and reservoir management in the North-Heera field, Mumbai Offshore Basin.

Reservoir Wellbore Stability Analysis and Weak Zones Identification Using the 1D MEM, Swelling Tests and UCS: A Case Study From Mumbai Offshore, India

Reservoir geomechanical studies play a decisive role in identifying wellbore instability and weak zones in offshore petroleum reservoirs. In this study, an integrated workflow developed with 1D Mechanical Earth Models (1D MEM), uniaxial compressive strength and swelling tests using well logs, drilling, and core data of production and exploratory wells from the North-Heera field, Mumbai offshore, India. Lithology-based correlations are utilized for calculating continuous profiles of rock mechanical properties by taking well logs as a primary source of input. Insights of fracture gradients and stresses are generated by interpretation of the pore pressure. UCS created from the well logs shows the low value of 15 MPa and high Poison's ratio of 0.38–0.45. Fracture pressure analysis of the wells specifies the lower fracture initiation pressures at 300 m are 5ppg–15ppg, which are shale and clay formation. Shale swelling tests are performed to know the hydration properties of shales present at shallow depths. The core samples' loading tests' results are very close to the UCS models constructed from the well logs. The combined analysis examines fracture pressures around wellbores, hydration of shales, weak zones identification, and wellbore instability.

High-Density Brine Used in Oil-Based Completion Fluid Deployed Offshore Norway

This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper SPE 199243, “First Use of a Newly Developed High-Density Brine in an Oil-Based Screen Running Fluid in a Multilateral Extended-Reach Well: Fluid Qualification, Formation Damage Testing, and Field Application, Offshore Norway,” by Bjarne Salmelid, Morten Strand, and Duncan Clinch, Halliburton, et al., prepared for the 2020 SPE International Conference and Exhibition on Formation Damage Control, Lafayette, Louisiana, 19–21 February. The paper has not been peer reviewed. When used for running sand-control screens, low-solids, oil-based completion fluids (LSOBCF) maintain reservoir wellbore stability and integrity while minimizing the potential risks of losses, screen plugging, completion damage, and productivity impairment. Until now, using LSOBCF as a screen running fluid has been limited by fluid density. The complete paper discusses the design, qualification, and first deployment of an LSOBCF that incorporates a newly developed, high-density brine as the internal phase to extend the density limit. Field History This new field’s well forms part of the greater Alvheim area located in the central part of the North Sea, close to the UK sector. The formations discussed present excellent reservoir characteristics but also significant drilling challenges. The intruded country rock tends to have a high shear failure gradient (SFG) combined with a relatively low fracture gradient. Furthermore, because these reservoirs are exploited using long horizontal and multilateral wells, the drilling window is relatively narrow. For the presented case, the SFG was anticipated to be 1.39 specific gravity (SG) equivalent mud weight with an equivalent circulating density limit of 1.49 SG and stretch limit of 1.53 SG. The fluid density chosen to drill the well was 1.40 SG, and the density for the screen running fluid was planned to be 1.45 SG. Fluids Qualification Laboratory Testing Matrix. An extensive laboratory test matrix was initiated for the qualification of reservoir fluids. The reservoir fluid and drill-in fluid (RDIF) qualification is not detailed in the paper, only the LSOBCF and the novel brine used to prepare this fluid. The test matrix included tests such as rheology performance, long-term stability, production screen on 275 µm screen coupons, standard fluid-loss and filter-cake repair capabilities, reservoir fluid and RDIF compatibility tests, true crystallization temperature (TCT), and corrosion rate. The ultimate test was to check for formation and completion damage performance.

Reservoir optimized plunger lift technology reduces hydrocarbon emissions from aging gas wells

Gas well liquification is a problematic process whereby liquids collect in the wellbore and near wellbore reservoir resulting in production impedance in aging gas wells. Removal of these liquids is traditionally performed through human operated blowdown events; however, this practice results in the release of hydrocarbon emissions into the atmosphere. The removal process, called ‘deliquification’, can also be accomplished through the utilization of various plunger lift technologies. These allow the extraction of retained fluids from the wellbore and near-wellbore reservoir; however, these technologies vary greatly with respect to automation, intelligence, and efficacy. Here we examined the rates of production loss and the frequency of emission events in mature natural gas wells equipped with various automated plunger lift technologies. Overall, ‘intelligent’ plunger lift systems that base their optimization on reservoir and wellbore conditions, as opposed to standardized or scheduled operations, performed the best exhibiting a 0.13% loss of production gas to atmospheric emissions compared to a 1.37% loss of production observed from wells without a plunger lift system. Additionally, wells equipped with a next generation reservoir optimized plunger lift demonstrated a reduced rate of production decline compared to those wells without a plunger lift technology (−0.066%/day and −0.242%/day, respectively). These data have widespread implications for the operational and environmental management of a consistently increasing count of aging natural gas production wells.

A Hybrid Optimization Methodology Identifying Optimal Operating Conditions for Carbon Dioxide Injection in Geologic Carbon Sequestration

Prior to determining the optimal operating parameters for CO2 injection, conditions for both injection wellbore and storage formation should be evaluated; the build-up pressure induced by the CO2 injection could promote fractures in the storage formation, even collapsing the wellbore. In this study, a hybrid optimization methodology, which combined the proxy modeling and multi-objective optimization, was engaged in searching appropriate operating conditions for CO2 injection. The study utilized a fully coupled wellbore-reservoir (WR) model to simulate the CO2 injection scenarios. Three responses, such as pressure, temperature, and CO2 mass flow rate at the bottom-hole of injection wellbore, were investigated. To reduce the computational cost, the statistical proxy models were developed for approximating three responses. The developed fine-tuned proxy models revealed four influential factors; wellhead pressure, injected CO2 temperature, wellbore diameter, and permeability of a storage formation were significant in predicting three responses. Among these four influential factors, permeability was treated to be an uncertainty factor, while the other three factors were treated as tuning factors. According to acquired optimal solution sets, the optimum values for wellhead pressure and injected CO2 temperature were distributed around 10.0 MPa and 35 °C, respectively. For the wellbore diameter, its mean of optimal solutions was 0.1 m, and more solutions were concentrated at this mean value with a decrease in permeability.

Thermal and fluid processes in a closed-loop geothermal system using CO2 as a working fluid

A co-axial closed-loop geothermal system is a new method to extract geothermal energy. It uses a continuously closed wellbore and the closed system can avoid many problems of traditional geothermal development methods, such as reservoir blockage and heat transmission fluid leakage. Generally, water as a working fluid will cause a series of problems which are not conducive to the operation and maintenance of the geothermal system. Recently, using CO2 as a working fluid has attracted considerable attention. CO2 has a larger mobility and buoyancy that result from its lower density and viscosity. However, a large flow rate will lead to incomplete heating of the working fluid, which will reduce the thermal performance of the geothermal system. In addition, CO2 has a smaller specific enthalpy, which is not beneficial to the heat extraction of the geothermal system. Therefore, it is necessary to study the advantages and disadvantages of CO2 and water as working fluid. In this work, a wellbore reservoir coupled model is built to simulate the operation fluid flow and thermal processes in a co-axial closed-loop geothermal system. The difference in productivity between water and CO2 as working fluids is investigated. The fluid flow and thermal processes of CO2 and water along the wellbore and the heat-extracting mechanism are analysed. The results show that although CO2 is more efficient, its output temperature is lower than water. Therefore water is still suitable for geothermal reservoirs with lower temperature. The modelling and analysis methods presented here may provide a theoretical reference for the selection of a working fluid in geothermal engineering developments.

Numerical evaluation of building heating potential from a co-axial closed-loop geothermal system using wellbore–reservoir coupling numerical model

Geothermal energy is one of the most potential renewable energy resources. How to efficiently extract and utilize geothermal energy has been a worldwide hot topic. Co-axial closed-loop geothermal system is a novel method using a continuously closed wellbore without water exchange with. It is more suitable for reservoirs with medium or low temperature and permeability because many problems could be avoided such as lack of in situ groundwater or low infectivity of the reservoir. Many companies and research institutes have applied closed-loop geothermal system in building heating engineering and some fine results have been gained. However, in practical engineering construction, the area of a closed-loop geothermal system heating system is a very important parameter. It directly determines the cost accounting and initial design of the project. Accurate and reliable estimation of heating capacity becomes very important. In this study, a wellbore–reservoir coupling model is established, which is calibrated using measured data from a short-term field trial operation. We have carried out mixed convective–conductive fluid-flow modeling using a wellbore flow model for TOUGH2 called T2Well to investigate the heat extraction performance of closed-loop geothermal system. The system evolution and the effect of flow rate and injection temperature on heat production performance are discussed. The result shows that the intermittent production cycles are more beneficial for heat extraction and system maintenance, and the temperature recovery between two heating seasons is enough to maintain system heating. And we can calculate that a geothermal well can ensure heating of buildings of 10,000–20,000 m2 and the heating area of intermittent operation is 4000 m2 more than continuous operation. Besides, the sensitivity analysis of parameters is also carried out.