Long-term Gas Production Research Articles

High-precision monitoring and point location optimization method of natural gas micro-leakage in the well site of salt cavern gas storage

The operation equipment in the well site of salt cavern gas storage is complicated. The potential leakage sources, such as wellhead, valve group and pipelines, are widely distributed, so the probability of micro-leakage events in the well site is very large under the long-term gas injection and production conditions. Aiming at the characteristics of well site layout and the existing problems of present gas detectors, such as low accuracy, multiple points, environmental influencing factors and poor stability, a high-precision monitoring and point location optimization method for natural gas micro-leakage at the well site was proposed. Firstly, an opposite-beam laser methane detector was selected after compared with different combustible gas monitoring methods, and used to monitor the gas micro-leakage at the key zones of well site which have the most probable leakage in real time. Then, a micro-leakage monitoring probability simulation model was established and the gas leakage diffusion law in the well site under different conditions were studied, such as different wind directions, wind speeds, gas leakage points and leakage rates. Finally, a high-precision monitoring method and a point location optimization scheme were proposed under the constraint conditions of economy and monitoring probability after compared with different layout paths. The detecting precision of leak gas concentration can be up to 1.0 ppm m after the improvement of the model. The real-time monitoring and effective early warning of micro-leakage in the well site of salt cavern gas storage can be realized, which can effectively reduce the risk of leakage event after the failure of gas storage leak proofness and ensure the long-term safety monitoring and efficient operation for salt cavern gas storage.

Geochemical Characteristics and Productivity Evaluation of Water Produced from Coalbed Methane Wells in the Laochang Block, Eastern Yunnan.

The water produced from coalbed methane (CBM) wells contains abundant hydrogeochemical information, which is of great significance for the productivity evaluation of CBM wells. Based on the analysis of the conventional ions, hydrogen and oxygen isotopes, and trace elements in the water produced from three CBM wells in the Laochang Block, eastern Yunnan, the geochemical characteristics of the water produced from three CBM wells and their impacts on productivity are analyzed. The results show that the conventional ions in the water produced from all the three CBM wells in the study area exhibit similar characteristics, with low concentrations of Ca2+, Mg2+, SO42-, and F-, medium concentrations of K+, and high concentrations of Na+, Cl-, and HCO3-. As the drainage time increased, the water produced from wells S-2 and S-3 changed from the Na-Cl-HCO3 type to the Na-HCO3 type, while the water produced from well S-1 remained the Na-Cl-HCO3 type. The concentrations of HCO3- and F- are roughly positively correlated with the gas production, with higher gas production at concentrations of approximately 2000 and 2 mg/L, respectively. The gas production from well S-1 is relatively low, and it is speculated that this situation is caused by reservoir damage. The gas production from well S-2 is the lowest among the three wells in the study area, and it is speculated that the cause of this phenomenon is roughly due to breakage of the sandstone at the top of the coal seam or collapse of the wellbore, which communicates with the aquifer. Based on the characteristics of the water production from well S-3 with a good gas production, a quantitative characterization range of trace element changes in the water production from CBM wells is proposed. σY values of around 1500 μg/L and σM values of 0.4-0.5 μg/L are beneficial for the long-term gas production.

Unraveling the complex pressure propagation of two-time depressurization production in Shenhu hydrate reservoir: Insights for long-term exploitation

Depressurization serves as the primary method for exploiting marine hydrate reservoirs, and understanding the long-term pressure propagation efficiency and identifying the potential limiting factors are crucial for enhancing and optimizing this approach. In this study, we employed numerical modeling to simulate two-time depressurization exploitation in the Shenhu hydrate reservoir, aiming to predict the long-term gas production and pressure propagation efficiency under various depressurization schemes. Our simulation results indicate: 1) The pressure propagates rapidly near the wellhead and gradually decelerates with distance due to the impeding influence of the reservoir's low intrinsic permeability and groundwater seepage in the covering strata. 2) Pressure propagation in single-well systems exhibits substantial variation among sublayers, resulting in limited areas of hydrate dissociation. Long-term gas production depends on the hydrate dissociation. Consequently, the total 5-year gas production for single-vertical-well and single-horizontal-well systems are only 3.59 × 106 m3 and 5.04 × 106 m3, respectively. 3) Multi-horizontal-well systems can significantly extend pressure propagation, but the maximum increase in gas production is only 47.0%. This is due to the reservoir's low permeability (2.3 mD), which severely hampers hydrate dissociation pressure, limiting it to 8 MPa. Therefore, optimizing depressurization requires reservoir modifications to enhance reservoir permeability.

Enhanced gas production from silty clay hydrate reservoirs using multi-branch wells combined with multi-stage fracturing: Influence of fracture parameters

Natural gas hydrates are typically deposited in low-permeability clayey-silty sediments with low gas production. The two main methods for enhancing gas production are complex structural wells and hydraulic fracturing. However, using only one of those methods does not significantly increase gas production. Herein, a method of combined multi-branch well with multi-stage fracturing was proposed. A novel evaluation method for increased gas production under fracturing was first proposed to reveal the effects of fracturing domain area and number. Then five fracturing distribution models were designed and analyzed. Results indicate that the combined method increased the gas recovery ratio by 829.13% and the hydrate dissociation ratio by 710.34% compared to branching wells because of enlarging pressure propagation and communicating deep thermal fluids. The dissociation of hydrates is enhanced by an increase in the area and the number of fractures, but the rangeability of the increased stimulating effect declines. Different fracture distributions influence production performances at different stages. Short-term production is beneficial when fractures are in the branch well centers. Long-term gas production can be improved when fractures are mainly located at the branch distal end. This novel study has important implications for commercial exploitation at different production stages.

Application of image-based diffusion coefficients in multi-scale simulation of coalbed methane reservoirs

Gas diffusion in coalbed methane (CBM) reservoirs is a multi-scale process. It can be a dominant factor in long-term gas production performance. Producing coalbed methane requires a detailed understanding of diffusion behaviours and their contribution to production. This paper develops a core-scale model based on micro-CT images. Our model considers free and adsorbed gas diffusion, sorption, and viscous flow. It also includes the effect of swelling, gas moisture, and effective stress. Following that, it is used to simulate gas flow on micro-CT images. The simulation results quantify the influence of effective stress on gas diffusion in coal. The core-scale model is then coupled to the large-scale simulation, where we compare the gas production curves against the result based on the assumption of a constant diffusion coefficient. This model can be used to calculate the effective diffusion coefficient from a micro-CT image and to predict the production performance at the reservoir scale reliably using a coupled multi-scale approach.

Well Testing Methodology for Multiple Vertical Wells with Well Interference and Radially Composite Structure during Underground Gas Storage

To achieve the goal of decarbonized energy and greenhouse gas reduction, underground gas storage (UGS) has proven to be an important source for energy storage and regulation of natural gas supply. The special working conditions in UGS cause offset vertical wells to easily interfere with target vertical wells. The current well testing methodology assumes that there is only one well, and the interference from offset wells is ignored. This paper proposes a solution and analysis method for the interference from adjacent vertical wells to target vertical wells by analytical theory. The model solution is obtained by the solution with a constant rate and the Laplace transform method. The pressure superposition is used to deal with the interference from adjacent vertical wells. The model reliability in the gas injection and production stages is verified by commercial software. Pressure analysis shows that the heterogeneity and interference in the gas storage are caused by long-term gas injection and production. As both the adjacent well and the target well are in the gas production stage, the pressure derivative value in radial flow is related to production rate, mobility ratio, and 0.5. Gas injection from offset wells will cause the pressure derivative to drop later. Multiple vertical wells from the Hutubi UGS are used to illustrate the properties of vertical wells and the formation.

Permeability Models of Hydrate-Bearing Sediments: A Comprehensive Review with Focus on Normalized Permeability

Natural gas hydrates (NGHs) are regarded as a new energy resource with great potential and wide application prospects due to their tremendous reserves and low CO2 emission. Permeability, which governs the fluid flow and transport through hydrate-bearing sediments (HBSs), directly affects the fluid production from hydrate deposits. Therefore, permeability models play a significant role in the prediction and optimization of gas production from NGH reservoirs via numerical simulators. To quantitatively analyze and predict the long-term gas production performance of hydrate deposits under distinct hydrate phase behavior and saturation, it is essential to well-establish the permeability model, which can accurately capture the characteristics of permeability change during production. Recently, a wide variety of permeability models for single-phase fluid flowing sediment have been established. They typically consider the influences of hydrate saturation, hydrate pore habits, sediment pore structure, and other related factors on the hydraulic properties of hydrate sediments. However, the choice of permeability prediction models leads to substantially different predictions of gas production in numerical modeling. In this work, the most available and widely used permeability models proposed by researchers worldwide were firstly reviewed in detail. We divide them into four categories, namely the classical permeability models, reservoir simulator used models, modified permeability models, and novel permeability models, based on their theoretical basis and derivation method. In addition, the advantages and limitations of each model were discussed with suggestions provided. Finally, the challenges existing in the current research were discussed and the potential future investigation directions were proposed. This review can provide insightful guidance for understanding the modeling of fluid flow in HBSs and can be useful for developing more advanced models for accurately predicting the permeability change during hydrate resources exploitation.

Optimal design of the field hydrate production test in the offshore India: Insights from the vertically heterogeneous hydrate reservoir model

Recently, the hydrate-bearing sand reservoirs were founded with high saturation in the offshore India by the National Gas Hydrate Program Expedition 02 (NGHP-02). Based on the detailed geological data at the NGHP-02-16 site, a more realistic reservoir model is constructed to analyze the unique multiphase flow and hydrate phase change behaviors from the geologically descriptive hydrate reservoirs. The main goals of this work are to optimize the adjustable production parameters and to predict the long-term gas production performance for guiding the upcoming field hydrate production test in India. The results indicate that gas production rates increase, but water production rates decrease slowly with time from the heterogeneous hydrate-reservoir. This is completely different from the previous prediction of multiphase flow behavior based on homogeneous hydrate-reservoir models. A non-uniform hydrate dissociation front is formed in the hydrate-reservoir due to the reservoir heterogeneity promote the horizontal dissociation of solid-hydrate within the high permeability sand layers. The maximum distance of free gas zone expands to outside more than 500 m from the production well. This indicates that the field fault system should be carefully concerned during the long-term production. Sensitivity analysis results suggest that the complete perforation in the hydrate-bearing layer and the underlying water saturated layer is beneficial for improving the hydrate production performance. Over the 5 years depressurization, a total of 2.08 × 107 ST m3 methane gas can be produced using the recommended well placement. The average gas-to-water ratio and energy ratio reach 10.22 ST m3 CH4/m3 H2O and 30.14, respectively, showing a high gas production potential from this hydrate site.

Nonlinear Diffusion-Based Multifield Coupling Model for Thermally Enhanced CBM Recovery

Thermal stimulation is a supplementary technique for enhancing gas recovery from coalbed methane (CBM) reservoirs that has received considerable attention worldwide. Investigating gas and heat transfer in coal seams during thermally enhanced CBM recovery is of great significance for predicting gas production and optimizing the extraction method. Gas diffusion in the coal matrix and coupled multiphysics are two of the most important aspects when analyzing gas migration and heat transport. However, previous studies either neglected the nonlinear diffusion process of gas or only assumed that the diffusion coefficient varies with production time. However, considerable experimental results indicate that the gas diffusion coefficient is not only determined by time but also by temperature, which strongly impacts multifield interaction during gas recovery. Thus, prior diffusion models and coupled models must be modified. In this paper, a time-and-temperature-dependent gas diffusion model is established based on fractal theory and experimental data. The proposed diffusion model is embedded into the coupled thermal-hydro-mechanical model to comprehensively describe the behavior of coal deformation, gas migration, and heat transport during CBM recovery. Additionally, both new diffusion model and coupled model were validated with experimental results or field test data, showing that these developed models are applicable for modeling long-term gas diffusion and gas production. Finally, the coupled model was implemented into COMSOL Multiphysics software, and a series of numerical simulations were conducted. The calculation results showed that heat injection could promote gas desorption and diffusion in the matrix while inhabiting gas flow in fractures near the injection well. Gas dynamic diffusion could inhabit gas migration in both matrix system and fracture system at a later production stage. This also means that ignoring the gas nonlinear diffusion process leads to a severe overestimation of coal permeability and gas production.

Numerical analysis on gas production from heterogeneous hydrate system in Shenhu area by depressurizing: Effects of hydrate-free interlayers

Natural gas hydrates (NGHs) buried in the Shenhu area are characterized by fine-grained sediments with interbedded hydrate-free layers. However, few is known about the influence of hydrate-free interlayers (HFIs) on gas production, which may control efficient and safe gas recovery from NGH reservoirs in long-term production. In this study, a field-data-based heterogeneous reservoir model is established to evaluate gas production behavior of Shenhu NGH reservoir with HFIs during depressurization. We compare the gas production from the hydrate reservoir with different HFIs characteristics. In a vertical well configuration, NGHs adjacent to HFIs dissociate preferentially over time, thereby significantly increasing average methane production and gas-to-water ratio. Notably, highly permeable HFIs (especially those near the permeable underburden), which can be regarded as high-permeability channels, increase pressure diffusion and then fluid flow, heat transfer and long-term gas production efficiency. The interlayers provide a better pathway for gas migration and secondary hydrates form inhomogeneously in the dissociation front. In contrast, low-permeability HFIs can negatively affect gas production and decrease average gas production amount by nearly 32.4% at most. The HFIs with low permeability are unfavorable for fluid migration and convective heat transfer from the burdens. Under the same initial conditions, the alternative of single horizontal well promotes the gas extraction volume limitedly. This study suggests that the vertical well configuration may provide more promising gas production efficiency than that of the horizontal one for the heterogeneous NGH reservoirs with HFIs in vertical direction. Our finding can provide a useful guide for gas production strategy in NGH reservoirs with HFIs.

Numerical investigation on the long-term production behavior of horizontal well at the gas hydrate production site in South China Sea

The gas hydrates-bearing shaly silt reservoirs have the characteristics of high reserves and low permeability. The trial production test in South China Sea in 2020 shows that horizontal well has broad prospects for exploiting this kind of hydrate reservoir. However, due to the short trial production time, the long-term gas production behavior is still unknown and needs further investigation. Based on the trial production data, the geological model of multi-layer hydrate reservoir and multi-physical field coupling mathematical model are established. The influence of optimization of depressurization scheme and optimization of reservoir selection on the improvement of gas production efficiency and the influence of compaction effect on attenuation of gas production rate and reservoir stability are investigated. The results show that the pressure drop gradient and constant pressure duration are the key factors affecting step-wise depressurization. The constant pressure duration of single-stage depressurization is more appropriate between 5 and 10 days. When the pressure drops below the equilibrium pressure of hydrate phase, the pressure drop gradient of 0.2 MPa/d is the best for long-term stable gas production. On the other hand, the low permeability of HBL inhibits pressure drop propagation and heat transfer in this sublayer, keeping the gas production rate at a low level in the later stage of production. Further simulation shows that HBL with hydrate saturation of 19% ∼ 25% should be selected for the target reservoir in order to improve gas production efficiency. In addition, the compaction effect in the hydrate decomposition zone is obvious. Compared with the 30 days, the near-well effective permeability drops by more than 30% at 720 days, which is an important reason for the decrease of gas production rate in the later stage of production. Finally, the formation subsidence increases with the expansion of hydrate decomposition radius. The maximum formation subsidence is 0.31 m after 720 days of exploitation.

Prospects of gas production from the vertically heterogeneous hydrate reservoirs through depressurization in the Mallik site of Canada

Natural gas hydrate (NGH) is a clean and efficient energy resource with extensive distribution in the permafrost regions and marine sediments. A few short-term production tests focusing on reservoir depressurization have been conducted in recent years. However, the long-term production performance and the transient evolution characteristics of reservoir properties are not well known. In this work, a more realistic hydrate-reservoir model that considers the heterogeneity of permeability, porosity and hydrate saturation is constructed, according to the available geological data at the Mallik site. The model is validated by reproducing the field depressurization test. The main purposes of this work are to evaluate the long-term gas production performance and to analyze the unique multiphase flow behaviors from the validated geologically descriptive hydrate-reservoir model. The results indicate that the long-term gas production through depressurization from hydrate reservoirs at the Mallik site is technically feasible, but the gas production efficiency is generally modest. The hydrate dissociation front in HBS is strongly affected by the reservoir heterogeneity and shows a unique dissociation front. The vertically heterogeneous HBS is beneficial for depressurization production compared to the massive hydrate reservoirs. Furthermore, the vertically heterogeneous hydrate-reservoir with low permeability of clay-layer can effectively block methane gas diffusion in the vertical direction. These emphasize that constructing realistic reservoir models is very important to accurately predict the hydrate production performance. At the end of 1-year depressurization, a total of 1.80 × 106 ST m3 of methane gas can be produced from the validated hydrate-reservoir, while which is far from the commercial value. In addition, reducing the production pressure in the wellbore is beneficial for increasing gas production volume, but is not conducive to improving the hydrate production efficiency at the Mallik site.

Forecasting Long-Term World Annual Natural Gas Production by Machine Learning

Forecasting Long-Term World Annual Natural Gas Production by Machine Learning

Mechanism of the Production Impact in Shale Gas Wells Caused by Water Invasion during Interwell Interference.

Interwell interference is a universal problem in shale gas development and can cause severe reductions in the productivity of producing wells. Studies have attempted to identify the root cause of interference in producing wells, but the mechanisms of production reduction and recovery in impacted wells are still not clear. Thus, an effective preventive strategy is needed for producing wells when fracturing is performed in adjacent wells. According to the mechanism of spontaneous imbibition and water drainage in shale mico- and nanoscale pores, this paper introduces the water–gas distribution during fracturing and production and reveals that water drainage in micro- and nanoscale pores is mainly controlled by the amount of stored gas and follows the order of pore size. Based on this analysis, the mechanism by which interwell interference impacts the production of producing wells is explained for the first time. It is concluded that the secondary water invasion caused by interwell interference completely blocks the pores associated with long-term gas production but has little influence on the pores that have not yet drained or have produced only a small amount of gas, and smaller pores face a greater risk of water blockage. The proportion of drained pores formed during long-term gas production determines the effect of interwell interference on production; when more pores are drained by long-term gas production, greater damage occurs to the productivity of the producing well. The suggestion for preventing interwell interference is to reduce the time interval between fracturing operations at two adjacent wells, thereby diminishing the reduction in production.

Effect of well configuration, well placement and reservoir characteristics on the performance of marine gas hydrate reservoir

Reservoir simulations are used to forecast the long-term gas production from gas hydrate reservoirs. In the present work, we explore different well placements and well configurations to analyze the gas production strategy for an oceanic, unconfined, class-2, gas hydrate reservoir using an in-house three-dimensional finite volume simulator. In the past, for depressurization in an unconfined class-2 reservoirs, isolation of the aquifer zone by well placement is suggested. We show that for high pressure conditions in marine gas hydrate reservoirs, depressurization is ineffective even with horizontal producer placed far away from the aquifer. Therefore, Warm water injection is necessary along with depressurization. We demonstrate that, the injector placement and configuration determines the gas production behavior and producer conditions do not significantly impact the production potential. We also find that the unconfined aquifer below the hydrate zone helps in the warm water convection and proximity of the injector to the aquifer improves gas production behavior. However, for unconfined class-2 gas hydrate reservoirs with low initial pressure, depressurization is effective and leads to a very high recovery (80%) of the gas. The reservoir porosity governs the warm water injection which affects the available dissociation energy to the gas hydrates and hence the gas recovery. In a layered reservoir, the porosity of the hydrate layer adjacent to the overburden has significant impact on the gas production due to the available dissociation energy from the overburden.

Geomechanical Response Induced by Multiphase (Gas/Water) Flow in the Mallik Hydrate Reservoir of Canada

Summary Natural gas hydrate (NGH) is regarded as an important alternative future energy resource. In recent years, a few short-term production tests have been successfully conducted with both permafrost and marine sediments. However, long-term hydrate production performance and the potential geomechanical problems are not very clear. According to the available geological data at the Mallik site, a more realistic hydrate reservoir model that considers the heterogeneity of porosity, permeability, and hydrate saturation was developed and validated by reproducing the field depressurization test. The coupled multiphase and heat flow and geomechanical response induced by depressurization were fully investigated for long-term gas production from the validated hydrate reservoir model. The results indicate that long-term gas production through depressurization from a vertically heterogeneous hydrate reservoir is technically feasible, but the production efficiency is generally modest, with the low average gas production rate of 4.93 × 103 ST m3/d (ST represents the standard conditions) over a 1-year period. The hydrate dissociation region is significantly affected by the reservoir heterogeneity and reveals a heterogeneous dissociation front in the reservoir. The depressurization production results in significant increase of shear stress and vertical compaction in the hydrate reservoir. The response of shear stress indicates that the potential region of sand migration is mainly in the sand-dominant layer during gas production from the hydraulically heterogeneous hydrate reservoir (e.g., sand layers interbedded with clay layers). The maximum subsidence is approximately 78 mm and occurred at the 72nd day, whereas the final subsidence is slowly dropped to 63 mm after 1-year of depressurization production. The vertical subsidence is greatly dependent on the elastic properties and the permeability anisotropy. In particular, the maximum subsidence increased by approximately 81% when the ratio of permeability anisotropy was set at 5:1. Furthermore, the potential shear failure in the hydrate reservoir is strongly correlated to the in-situ stress state. For the normal fault stress regime, the greater the initial horizontal stress is, the less likely the hydrate reservoir is to undergo shear failure during depressurization production.

Numerical evaluation on the effect of horizontal-well systems on the long-term gas hydrate production behavior at the second Shenhu test site

In 2019–2020, the second natural gas hydrate field trial was successfully performed in the Shenhu Area of the South China Sea by using a horizontal well, however, the long-term production performance is unclear and needs intensive surveys. In this work, a multilayered hydrate reservoir model was constructed to replicate the short-term test result on the basis of the field data obtained at this site for the first time. Then, the long-term gas hydrate production behaviors at this site by using the single-horizontal-well and dual-horizontal-well systems were investigated, and the production strategy of thermal stimulation was proposed to examine the effects of the injection parameters of the hot water on the enhanced gas recovery. From the analysis of the simulation results, it can be known that due to the extremely low permeabilities of the whole reservoir (2.38–6.8 mD), the 10-yr average gas production rates (7.71 × 102–2.88 × 103 m3/d) could only reach 1/10 of the level obtained in the second Shenhu field trial (2.87 × 104 m3/d), which indicated that none of the above methods were quite suitable for future commercial gas production at this site. Therefore, it is recommended that permeability enhancement should be implemented in advance to improve the reservoir permeability before the actual long-term gas production.

Effect of Geological Heterogeneity on the Production Performance of a Multifractured Horizontal Well in Tight Gas Reservoirs

AbstractMultifractured horizontal wells are widely used in the development of tight gas reservoirs to improve the gas production and the ultimate reservoir recovery. Based on the heterogeneity characteristics of the tight gas reservoir, the homogeneous scheme and four typical heterogeneous schemes were established to simulate the production of a multifractured horizontal well. The seepage characteristics and production performance of different schemes were compared and analyzed in detail by the analysis of streamline distribution, pressure distribution, and production data. In addition, the effects of reservoir permeability level, length of horizontal well, and fracture half-length on the gas reservoir recovery were discussed. Results show that the reservoir permeability of the unfractured areas, which are located at both ends of the multifractured horizontal well, determines the seepage ability of the reservoir matrix, showing a significant impact on the long-term gas production. High reservoir permeability level, long horizontal well length, and long fracture half-length can mitigate the negative influence of heterogeneity on the gas production. Our research can provide some guidance for the layout of multifractured horizontal wells and fracturing design in heterogeneous tight gas reservoirs.

The Application of Integrated Assisted History Matching and Embedded Discrete Fracture Model Workflow for Well Spacing Optimization in Shale Gas Reservoirs with Complex Natural Fractures

An appropriate well spacing plan is critical for the economic development of shale gas reservoirs. The biggest challenge for well spacing optimization is interpreting the subsurface uncertainties associated with hydraulic and natural fractures. Another challenge is the existence of complex natural fractures. This work applied an integrated well spacing optimization workflow in shale gas reservoirs of the Sichuan Basin in China with both hydraulic and natural fractures. The workflow consists of five components: data preparation, reservoir simulation, estimated ultimate recovery (EUR) analysis, economic calculation, and well spacing optimization. Firstly, the multiple realizations of thirteen uncertain parameters of matrix and fractures, including matrix permeability and porosity, three relative permeability parameters, hydraulic fracture height, half-length, width, conductivity, water saturation, and natural fracture number, length, and conductivity, were captured by the assisted history matching (AHM). The fractures were modeled by the embedded discrete fracture model (EDFM) accurately and efficiently. Then, 84 AHM solutions combining with five well spacing scenarios from 517 ft to 1550 ft would generate 420 simulation cases. After reservoir simulation of these 420 cases, we forecasted the long-term gas production for each well spacing scenario. Gas EUR degradation and well interference would imply the critical well spacing. The net present value (NPV) for all scenarios would be calculated and trained by K -nearest neighbors (KNN) proxy to better understand the relationship between well spacing and NPV. In this study, the optimum well spacing was determined as 793 ft, corresponding with a maximum NPV of 18 million USD, with the contribution of hydraulic fractures and natural fractures.

Stress Drop, Seismogenic Index and Fault Cohesion of Fluid-Induced Earthquakes

Sometimes, a rather high stress drop characterizes earthquakes induced by underground fluid injections or productions. In addition, long-term fluid operations in the underground can influence a seismogenic reaction of the rock per unit volume of the fluid involved. The seismogenic index is a quantitative characteristic of such a reaction. We derive a relationship between the seismogenic index and stress drop. This relationship shows that the seismogenic index increases with the average stress drop of induced seismicity. Further, we formulate a simple and rather general phenomenological model of stress drop of induced earthquakes. This model shows that both a decrease of fault cohesion during the earthquake rupture process and an enhanced level of effective stresses could lead to high stress drop. Using these two formulations, we propose the following mechanism of increasing induced seismicity rates observed, e.g., by long-term gas production at Groningen. Pore pressure depletion can lead to a systematic increase of the average stress drop (and thus, of magnitudes) due to gradually destabilizing cohesive faults and due to a general increase of effective stresses. Consequently, elevated average stress drop increases seismogenic index. This can lead to seismic risk increasing with the operation time of an underground reservoir.