Horizontal Wells Research Articles

Submarine slope stability during the exploitation of natural gas hydrate from horizontal wells

Horizontal wells have the advantages of high production, considerable access to reserves, and effective sand production control; thus, they are potential well types for hydrate exploitation. In the process of hydrate mining, the decomposition of hydrate will cause the deterioration of the mechanical properties of the reservoir, which may induce submarine landslides, especially in the case of multiple horizontal wells, and the risk of submarine landslides is further increased. Therefore, it is necessary to study the influence of the horizontal well pattern adopted for hydrate mining on the stability of submarine slopes. First, a triaxial mechanical experiment of gas hydrate-containing sediments was carried out, and the mechanical parameters of the hydrate-containing sediments were obtained. Second, a thermal-fluid-solid multifield coupling model considering the hydrate phase transition during the production process was established. Finally, on the basis of the finite element strength reduction method, a slope stability evaluation model for hydrate extraction from a horizontal well pattern was established, and the influence of hydrate extraction from horizontal wells on the stability of submarine slope was analyzed. The results show that the peak strength, elastic modulus and cohesion of gas hydrate-containing sediments increase with increasing hydrate saturation. In the process of hydrate exploitation via horizontal wells, with the reduction in well spacing and the increase in the number of production wells, the risk of slope instability increases. Wells positioned along the slope strike are more conducive to slope stability than those positioned perpendicular to the slope strike. The slope stability increases gradually as the slope dip decreases. When the number of wells is the same, the slope stability increases gradually with increasing well spacing and production pressure.

Productivity Model Study of Water-Bearing Tight Gas Reservoirs Considering Micro- to Nano-Scale Effects

Tight sandstone is rich in micron- and nano-scale pores, making the two-phase flow of gas and water complex. Establishing reliable relative permeability and productivity models is an urgent issue. In this study, we first used a slip model to correct the gas phase’s no-slip Hagen–Poiseuille equation for nano- and micropores. Then, combined with the fractal theory of porous media and the tortuous capillary bundle model, we established two-phase relative permeability models for nanopores and micropores. These relative permeability models comprehensively consider the gas slippage effect, the initiation pressure gradient, the pores’ fractal characteristics, and water film mechanisms. Based on these models, we developed a three-region coupling productivity model for water-bearing tight gas reservoirs with multi-stage fractured horizontal wells. This productivity model considered the micro- and nano-scale effects and the heterogeneity of fracture networks. Then, the model was solved and validated with a field case. The results indicated that the three-region composite unsteady productivity model for water-bearing tight gas reservoirs, which incorporated micro- and nano-scale effects (with consideration of micro-scale and nano-scale phenomena in the fluid flow), could accurately predict a gas well’s productivity. An analysis of the factors influencing productivity showed that ignoring the micro- and nano-scale effects in water-bearing tight gas reservoirs will underestimate the reservoir’s productivity. The initial water saturation, the two-phase flow’s initiation pressure gradient, and capillary force are all negatively correlated with the productivity of gas wells, while the conductivity of the fractures is positively correlated with gas well productivity.

A Two-Phase Flowback Type Curve with Fracture Damage Effects for Hydraulically Fractured Reservoirs

Summary Type curves are a powerful tool in characterizing hydraulic fracture (HF) and reservoir properties based on flowback and production data. We propose a type-curve method to evaluate HF characteristics and their dynamics for multifractured horizontal wells (MFHWs) in hydrocarbon reservoirs using flowback production data. The type curve incorporates the HF damage effect of choked-fracture skin factor in the two-phase flow in HF and matrix domains. The type-curve method can be applied to inversely estimate choked-fracture skin factor, s, HF pore volume (PV), Vfi, and HF initial permeability, kfi, by analyzing two-phase flowback production data. By introducing the new dimensionless parameters, the nonuniqueness problem of the type-curve analysis for two-phase flow is significantly reduced by incorporating the complexity of fracture dynamics into one set of curves. The accuracy of the type curve is examined against the results obtained from numerical simulations of shale gas and oil reservoirs. The validation results demonstrate a good match of analytical type curves and numerical data plots and confirm the accuracy of the proposed method in estimating the static and dynamic fracture properties. The results show that the relative errors in Vfi, kfi, and s estimations are all <10% for the simulated cases that are presented in this work. The flexibility and robustness of the proposed method are illustrated using the field example from a shale oil MFHW. The accuracy and applicability of the proposed type curve are also validated by comparing the calculated fracture properties from the field example using straightline analysis with Vfi and kfi of 705.3 Mcf and 245.2 md, type-curve analysis method (without skin effect) with Vfi and kfi of 751.9 Mcf and 249.8 md, and the type-curve method (with the choked fracture skin considered) with Vfi and kfi of 708.7 Mcf and 252.9 md, which showed that the results of each case are very close to one another. The interpreted results from the flowback analysis of the field example offer quantitative insight into HF properties and dynamics.

An Accurate Calculation Method on Blasingame Production Decline Model of Horizontal Well with Dumbbell-like Hydraulic Fracture in Tight Gas Reservoirs

Blasingame production decline is an effective method to obtain permeability and single-well controlled reserves. The accurate Blasingame production decline curve needs an accurate wellbore pressure approximate solution of the real-time domain. Therefore, the aim of this study is to present a simple and accurate wellbore pressure approximate solution and Blasingame production decline curves calculation method of a multi-stage fractured horizontal well (MFHW) with complex fractures. A semi-analytical model of MFHWs in circle-closed reservoirs is presented. The wellbore pressure and dimensionless pseudo-steady productivity index JDpss (1/bDpss) are verified with a numerical solution. The comparison result reaches a good match. Wellbore pressure and Blasingame production decline curves are used to analyze parameter sensitivity. Results show that when the crossflow from matrix to natural fracture appears after the pseudo-state flow regime, the value of the inter-porosity coefficient has an obvious influence on the pressure approximate solution of the pseudo-steady flow regime in naturally fractured gas reservoirs. The effects of relevant parameters on wellbore pressure and the Blasingame decline curve are also analyzed. The method of pseudo-steady productivity index JDpss can applied to all well and reservoir models.

Numerical simulation of multiple hydraulic fracture propagation in heterogeneous coal reservoirs based on combined finite-discrete element method

Multi-stage fracturing in Horizontal well increases the permeability of coalbed methane by generating multiple fractures. However, the heterogeneity of coal reservoirs is a crucial factor that cannot be ignored in the study of multiple hydraulic fracture propagation. Therefore, we established a two-dimensional model for multiple hydraulic fracture propagation based on the combined finite-discrete element method (FDEM) and assigned a Weibull distribution function to the heterogeneity of the physical parameters of the cohesive elements in the model. The objective was to simulate and study the fracture propagation law of multi-cluster fracturing in horizontal wells in heterogeneous coal reservoirs. The research results indicated that: 1) as the heterogeneity of the coal reservoir weakened, the deflection angle of the main fracture increased. More secondary fractures were generated in the coal reservoir, leading to significant discontinuity. 2) The fracturing disturbance area was always concentrated at the tip of the main fracture, with a double wing shape. However, the fracturing disturbance areas at the tips of multiple main fractures could easily converge, with a square shape; 3) It is recommended to use a moderate injection rate and increase the perforation spacing appropriately when hydraulic fracturing is carried out in coal reservoirs with a heterogeneity coefficient m=5.

Simulation of Proppant Placement in Multiple Simultaneously Propagating Hydraulic Fractures in Horizontal Wells

Simulation of Proppant Placement in Multiple Simultaneously Propagating Hydraulic Fractures in Horizontal Wells

Developing an inflow performance relationship for predicting hydrocarbon recovery from horizontal wells operating in partially naturally fractured reservoirs under solution-gas drive

Inflow performance relationships (IPR) have long been recognized as one of the most important diagnostic tools for predicting hydrocarbon production performance. Current IPR models associated with naturally fractured reservoirs (NFR) are only applicable to fully fractured NFR models. No previous research has investigated the IPR of partially naturally fractured reservoirs (PNFR). This work aims to develop an IPR model for horizontal wells producing from PNFRs under solution-gas drive (SGD). A 3D black oil simulator is utilized to generate the required IPR data. A total of 236 IPR plots and 26 future IPR plots are generated throughout six major cases varying in fracture intensity (FI), dimensionless well length (LD ), matrix permeability (km ), and fracture porosity (ϕf ). Percolation theory validated the existence of a critical FI threshold at which complex IPR behaviors manifest. Sensitivity analysis reveals that IPR shape becomes more complex as LD reduces. ϕf has negligible effects on IPR and future IPR behaviors. A logarithmic cycle proportionality governs the relationship between km and absolute open flow potential (qo,AOF ) in future IPR curves. A generalized IPR model applicable to horizontal wells producing from SGD PNFRs is developed through the non-linear regression of IPR candidates. The model is validated against field data and complex IPR behaviors.

Improving the technology for Inflow Profile Evaluation in horizontal Wells by temperature changes Due to calorimetric Mixing

The paper is devoted to the problem of increasing the effectiveness of temperature logging quantitative interpretation for the inflow profile evaluation in horizontal production wells draining heterogeneous reservoirs with low permeability. Such wells are characterized by an extremely uneven distribution of inflow along the length of the wellbore. One of the ways of quantitative interpretation of temperature logging is based on the effect of calorimetric mixing. It’s widely used to quantify the share of local producing intervals in the total flow rate.The low accuracy of interpretation is associated with the lack of reliable information about the temperature of the fluid flowing into the wellbore. The authors propose an estimate of this parameter based on the similarity of the behavior of the temperature field vs time in the near-wellbore zone of a reservoir during periods of stable production and the periods of the well shut-in. This relationship is confirmed by the results of modeling the temperature field of the “well – reservoir” system, taking into account changes in a wide range of reservoir permeability and thermal properties of the reservoir, the geometry of hydraulic fractures in the reservoir, the flowing fluids, as well as the parameters of the well production targets. The logging technology recommended by the authors involves the registration of several temperature profiles along the length of the wellbore at the beginning of the well production with the maximum rate and drawdown and during the well shut-in. Their integrated analysis based on the behavior of the temperature field features in time identified on the basis of modeling makes it possible to evaluate with a high degree of certainty the dynamics of the temperature of the gas-liquid mixture coming from reservoirs to the wellbore during production periods. This provides the required accuracy in the quantitative assessment of the inflow profile from mixing anomalies.The proposed approaches to the interpretation of thermograms are applicable in the analysis of the results of non-stationary temperature logging results in horizontal and vertical wells during the production from heterogeneous reservoirs both through perforation and multi-stage hydraulic fracturing.

Investigating the heated zone evolution and production performance of cyclic steam stimulation with horizontal well in thick-layer heavy oil reservoirs

Cyclic steam stimulation with horizontal well (CSSHW) has emerged as an efficient commercial recovery technique for heavy oil reservoirs. Accurately calculating the evolution of the heated zone and the production performance closely linked to it is crucial for addressing the economic and environmental issues that arise in the CSSHW process. Most previous analytical or semi-analytical models have relied on the assumption of uniform temperature distribution and have focused on thin-layer heavy oil reservoirs. In this study, through analyzing the evolution of the heated zone in the CSSHW experiment, the study observes that the temperature distribution within the heated region is non-uniform and exhibits a centrally symmetric distribution with the wellbore as the axis. Then, a semi-analytical model was developed to predict the heated zone evolution and production performance of CSSHW for thick-layer heavy oil reservoirs. Next, the model was validated using field data and numerical simulation. Finally, this study analyzed the evolution of the heated zone under a multi-cycle mode and examined the effects of various factors on oil production. The results reveal that the heat, the area, and the average temperature within the heated zone all increase with the number of cycles attributed to the influence of residual heat. Single-variable analysis indicates that increasing BHP reduces the pressure differential, lowering oil production, and that permeability significantly affects oil production. Multivariate analysis shows that lowering BHP with constant steam amount improves COSR or thermal efficiency. Lower steam amount achieves higher efficiency in high vertical or horizontal permeability reservoirs, while higher BHP maintains high efficiency in such reservoirs due to better fluid mobility. The temperature-dependent threshold pressure gradient (TTPG) analysis reveals that although TTPG reduces oil production, the reduction lessens with more cycles. TTPG's impact varies with steam amount, BHP, and permeability; increasing steam enhances TTPG's effect in low vertical or horizontal permeability reservoirs, while higher vertical or horizontal permeability reduces TTPG's effectiveness. This article provides a tool for rapid optimization and performance forecasting in thick-layer heavy oil field applications.

Optimization of Fine-Fracture Distribution Patterns for Multi-Stage and Multi-Cluster Fractured Horizontal Wells in Tight Gas Reservoirs

Optimization of Fine-Fracture Distribution Patterns for Multi-Stage and Multi-Cluster Fractured Horizontal Wells in Tight Gas Reservoirs

DEVELOPMENT AND TESTING OF A MODULE FOR CALCULATING THE PARAMETERS OF SCALE INHIBITORS SQUEEZE TREATMENT

Inorganic scale (salt) deposition in the oil and gas industry is a serious and widespread problem that requires timely measures for effective control and management. The process of formation and deposition of mineral salts depends on a large number of changing factors, which creates additional difficulties for predicting and controlling scale formation processes. The fields of Eastern Siberia, the formation waters of which belong to the category of brines with a mineralization of 250 g/l and more (in some cases more than 600 g/l), are characterized by the scale formation of complex composition (sulfate, carbonate and chloride salts). Scale deposits can occur in the near-wellbore zone of the formation, which can lead to a significant decrease in the productivity of production wells. Many fields in Eastern Siberia have a number of features that complicate their operation. Among them are low reservoir temperature (10–14 °C), reservoir pressure close to the saturation pressure and salinity (halitization) of the reservoir. In the practice of the global oil and gas industry, it has been repeatedly proven that the implementation of technologies to prevent scale deposits is much more technologically and economically efficient than removing already formed sediments. In this regard, the use of scale inhibitors (SI) is one of the key methods to combat the formation of salts. When scale deposits lead to disruption of the operation of submersible well equipment, technologies for continuous or periodic dosing of SI into the annulus of the well can be effective. To protect the bottomhole zone of the formation from scale deposits, the priority technology should be the injection of scale inhibitors or squeeze treatment into the formation under pressure.In this work, based on a set of laboratory filtration experiments, a module has been developed that allows calculating the volumes of scale inhibitor and process fluids required for SI squeeze into the reservoir. The successful results of two operations of SI squeeze into the formation of horizontal wells for protection against deposits of sulfate salts are shown.

ANALYSIS OF OIL RESERVES PRODUCTION AT THE BP8 DEVELOPMENT OBJECT OF THE TARASOVSKOYE OIL AND GAS CONDENSATE FIELD

Based on the example of the analysis of the development of the oil facility BP8 of the Tarasovskoye oil and gas condensate field, geological and technological factors that can cause a low current oil recovery factor with a high water cut of the product are considered. It is assumed that: 1) the low waterflood coverage coefficient is associated with artificial fracturing at the initial stage of development which led to a change in the type of reservoir from primary pore to porous-fractured; 2) a decrease in the displacement coverage coefficient is associated with the permeability heterogeneity of the object; 3) swelling of clay particles under the influence of injected fresh water led to a decrease in the displacement coefficient. An analysis of the development of the facility shows that without the use of new effective technological solutions for involving in the development of capillary-pinched oil reserves of the porous-fractured reservoir of the BP8 object, the final technological oil recovery factor will not exceed 0.240 instead of the approved 0.425. To increase development efficiency, it is recommended to carry out pilot work on drilling horizontal wells with multi-stage hydraulic fracturing, equipped with inflow control devices based on intelligent inflow indicators.

Retraction Note: Gray relational clustering model for intelligent guided monitoring horizontal wells

Retraction Note: Gray relational clustering model for intelligent guided monitoring horizontal wells

TECHNOLOGICAL SOLUTIONS FOR DRILLING USING FLEXIBLE TUBING – UP-TO-DATE WORLD EXPERIENCE AND PROSPECTS FOR RUSSIA

The article presents an analytical review of modern technologies for using flexible tubing to perform complex technological operations aimed at increasing oil recovery, exploration and repair of wells, and construction of lateral and horizontal wellbores. The authors have been most interested in the technology of underbalanced coiled tubing drilling, since it has the potential to increase oil production while maintaining or minimizing drilling costs without drilling complications while ensuring operational safety.The experience of a foreign company in coiled tubing drilling is reviewed, positive results and growth points are highlighted. Solutions for the implementation of coiled tubing drilling in Russian conditions are proposed to reduce the costs of constructing horizontal wells and additional hydrocarbon production during the drilling process. Preparatory work is underway to conduct pilot-industrial research of the proposed technology.

Fracture stratigraphy in oil-rich shale of the Upper Xiaganchaigou Formation (upper Eocene), western Qaidam Basin

Natural fractures in wells from oil-rich shale of the Upper Xiaganchaigou Formation in Qaidam Basin, the largest Cenozoic sedimentary basin in the Tibetan Plateau, vary systematically by stratigraphic position, allowing reconstruction of fracture generation processes during regional tectonic deformation. Compacted fractures, layer-bounded fractures, and low-angle (or bed-parallel) fractures were widely identified in oil-rich shale cores obtained from vertical wells. The layer-bounded fractures can be subdivided into two sets: one prevalent in light-colored (low gamma-ray) stiff layers and arrested by dark-colored (high gamma-ray) compliant layers, the other set primarily confined to the dark-colored compliant layers. The strikes of layer-bounded fractures, revealed by horizontal well FMI logs, are dominantly N60°-80°E and N10°-30°E within the light and dark intervals respectively. These strikes are consistent with natural hydraulic fracturing of the light layers during the Oligocene and the dark layers during the Middle Miocene-Holocene, based on a regional anticlockwise rotation of the compressional strain orientation. The abutment of layer-bounded fractures against low-angle (or bed-parallel) fractures in dark layers implies that the low-angle fractures were hydraulically fractured under a vertical least compressive stress during the Early Miocene, which produced the most intense tectonic compression. Layer-bounded fractures generally remain unmineralized in the dark layers but were mineralized in the light layers, suggesting that fractures confined in light layers would not decrease the sealing capacity of the shale oil system and fractures confined in dark layers can increase the pore space of shale oil storage. The Oligocene and Early Miocene fractures represented mechanical flaws that affected the initiation of Middle Miocene-Holocene fractures, implying that all natural fractures may alter hydraulic fracture stimulations to some extent.

Numerical validation of a novel cuttings bed impeller for extended reach horizontal wells

To reduce the risk of downhole accidents resulting from poor wellbore cleaning during the drilling of extended reach horizontal wells, a new cuttings bed impeller is developed. The performance of existing cuttings bed impellers on wellbore cleaning efficiency is analyzed by multiphase numerical simulation. Based on this analysis, a new type of cuttings bed impeller is proposed, and its key structure parameters are optimized. Its cuttings removal performance under different working conditions is verified. The results show that the spiral impellers have the highest annular velocity, promoting the movement of the cuttings bed. Increasing the rotation speed of the impeller causes the cuttings bed to move further from the low side of the wellbore, facilitating the cuttings removal. Two major improvements are introduced to the new cuttings bed impeller: a positive displacement motor that enables the self-rotation of the impeller, and the elastic contacts on the spiral blades that stir cuttings bed and reduce friction with the wellbore. The optimized parameters of the new impeller are: helix angle of 60°, 4 blades, elastic contacts arranged in crossed pattern, and self-rotation speed of 60 r/min. It is also demonstrated that the new impeller achieves satisfactory cleaning results in both rotary drilling (84.71%) and sliding drilling (71.07%) conditions. This work provides a new solution for the efficient removal of cuttings in extended reach horizontal wells.

Integrated Technique Provides Effective Water Diagnostics in Tight Sand

_ This article, written by JPT Technology Editor Chris Carpenter, contains highlights of paper URTeC 3864145, “Evaluating the Hydraulic Fracture Through Acoustic Reflection Imaging and Production Logging for Water Diagnostic Beyond the Wellbore: A Case Study From Chang 8 Tight Sand in the Ordos Basin, China,” by Guangsheng Liu, Dajian Li, and Gang Zheng, PetroChina, et al. The paper has not been peer reviewed. _ The Triassic Chang 8 tight sand reservoir in the Xifeng block of the Ordos Basin features low permeability, which means that hydraulic fracturing and subsequent waterflooding were performed during its development phase. Water breakthrough was encountered after a short period of oil production. A solution of borehole acoustic reflection imaging combined with production logging was proposed in a horizontal well suffering from high water cut. The objective was to determine which stages contributed most to water production, understand the cause, and, ultimately, create a water shutoff plan. Introduction The Ordos Basin, with an area of approximately 2.5×105 km2, is in North China. The Upper Triassic Yanchang formation is subdivided into the Chang 1 to 10 members, from top to bottom. It contains significant oil reserves in siltstone and sandstone reservoirs, especially in Chang 6 through Chang 8, that have been the major oil-producing resources in recent years. In the Triassic Chang 8 tight sand reservoir, horizontal well drilling and multiple-stage hydraulic fracturing have become common practice. In the study block, the well of interest was hydraulically fractured by coiled tubing with sand-jet perforation and fracturing operations in one run with a retrievable packer in the bottomhole assembly of the coiled tubing. In the study block, when some producing wells encountered water breakthrough, traditional water diagnostics using production logging was not enough; a survey to detect hydraulic fractures beyond the wellbore was needed. Theory and Methods Borehole Acoustic Reflection Imaging. The processing workflow for acoustic reflected waves mainly consists of two parts. The first is a filtering process to suppress the borehole mode and noise in order to preserve the reflected wave. The second is to migrate the reflected wave to the true position of a reflector. The conventional migration method used for acoustic reflection imaging normally requests previous information relating to reflector dip and produces 2D images, which show the reflector shape but have hard-to-extract precise quantitative information. A trial reflector-migration method covered in the literature was introduced in 2016 that does not require input of structure dip and is of high resolution. A 3D slowness-time-coherence method was developed in 2018, also covered in the literature, that could determine the true dip, azimuth, and distance of a reflector.

Coal measure gas resources matter in China: Review, challenges, and perspective

Achieving the dual carbon goals of peaking by 2030 and neutrality by 2060 is significantly aided by the growth of coal measure gas research and development, especially for China to optimize its primary energy consumption. We critically review the distribution, geological characteristics, methods of liberation and then recovery by hydraulic fracturing of coal measure gas in China and present a roadmap to optimize this recovery. The gas-bearing system is the focus of this recovery, but this system is embedded within its sedimentary environment and modulated by tectonic and hydrogeological controls that affect gas exploration and recovery. However, to improve the development of coal measure gas in China, bottleneck problems remain to be solved, such as accurately predicting reservoir behavior in dessert regions, optimizing well patterns, and deploying optimal horizontal well trajectories. Additionally, the technology breakthroughs on deep co-production of coal measure gas, automatic fracturing and intelligent drainage are imminent. Basically, developing new techniques and conducting improved geological surveys are essential to ensure the sustainable supply of coal measure gas resource. Thus, this review presents a comprehensive introduction to coal measure gas resources in China, of utility to academic researchers and engineers in enhancing the understanding of the current situation and in projecting future development.

Shale Oil Shut-In and Flowback Mechanism and Optimization Strategy

Abstract Shut-in and flowback are critical stages following hydraulic fracturing in shale oil wells. Researching the distribution of reservoir pressure and fluid flow mechanism during shut-in and flowback is important for optimizing these procedures, thereby enhancing well productivity. Therefore, based on the flow mechanism of shale oil, this article establishes a flow equation considering imbibition and seepage, using linear source superposition equivalent to the pressure distribution generated by hydraulic fracturing as the initial condition. The PEBI (Perpendicular BIsection) grid is used to divide the grid for multistage fractured horizontal wells. The simulation results reveal that large-volume fracturing leads to the formation of a high-pressure zone around the wellbore, significantly surpassing the original reservoir pressure, termed as the high-energy band. This high-energy band is demarcated from the original reservoir pressure by the pressure boundary line (PBL). During production, a double-pressure funnel (DPF) manifests within the reservoir, generating a region with the utmost pressure at a specific position within the high-energy band, known as the pressure peak line. Oil located beyond the pressure peak line is unable to flow toward the wellbore. According to the DPF theory of shale oil, fracturing technology should be adopted to form long straight fractures as far as possible whenever feasible to cross the high-energy band. The shale oil optimal duration for shut-in is contingent upon the movement rate of the pressure boundary and the shale imbibition curve.

Sealing faults and fluid-induced seismicity.

Sealing faults are nearly impermeable barriers that can form boundaries between subsurface pore-pressure domains. In hydrocarbon systems, sealing faults commonly form part of a structural trap; they are thus important elements for future storage of CO2 and other gases in depleted reservoirs. The Triassic Montney Formation in western Canada hosts low-permeability gas reservoirs containing sealing faults that have previously been assumed to compartmentalize pressure domains. In this study, we show that the distribution of induced seismicity associated with hydraulic fracturing (HF) exhibits a statistically significant spatial correlation with zones of high lateral gradient in pore pressure. These high-gradient zones are interpreted as sealing fault systems. The largest induced seismicity sequence, including a 4.5 ML mainshock on 30 November 2018, occurred during HF treatments in two horizontal wells, between which there is an exceptionally large contrast (~10 MPa) in measured pore pressure. Numerical simulation of a simplified model of a hydraulic fracture intersecting a nearby vertical fault, followed by fault rupture using rate-and-state friction rheology, generates results that are in good agreement with observed strike-slip faulting near one of the HF wells. Our study demonstrates that sealing faults exhibit previously unrecognized behaviour that may be important for understanding induced seismicity risk. This article is part of the theme issue 'Induced seismicity in coupled subsurface systems'.