Cumulative Injection Volume Research Articles

Assessment and optimization of maximum magnitude forecasting models for induced seismicity in enhanced geothermal systems: The Gonghe EGS project in Qinghai, China

Seismic activity induced during the development of Enhanced Geothermal Systems (EGS) is frequent and poses significant hazards. This study aims to accurately forecast the maximum magnitude (Mmax) of induced earthquakes to effectively manage seismic risks. Focusing on the EGS project in Gonghe County, Qinghai Province, we evaluated and optimized various widely-applied Mmax forecasting models, while also endeavoring to directly forecast maximum magnitudes in the post-closure phase. Initially, advanced deep learning models (such as PhaseNet and GaMMA) were employed to process seismic data, coupled with VELEST and HypoDD methods for earthquake relocation. Subsequently, four currently widely recognized maximum magnitude (Mmax) forecasting models (H14, NRBE, V16, and G17) were utilized to forecast and assess Mmax during nine hydraulic fracturing stages, six post-closure stages exhibiting tailing effects, and the entirety of the 2019–2021 period in the Gonghe EGS project. The findings indicate significant disparities in the efficacy of different forecasting models during hydraulic fracturing stages, with no model fully aligning with the complex physical mechanisms of induced seismicity. NRBE and G17 models tend to overestimate Mmax forecasting, potentially escalating production costs, whereas H14 and V16 models yield results closer to actual values but are susceptible to the influence of real seismic breakthroughs. Furthermore, distinct discrepancies were observed in the Mmax forecasting performance of the same model between hydraulic fracturing and post-closure stages. Attempts to directly forecast Mmax post-closure achieved certain efficacy, likely due to the cumulative injection volume exerting a degree of control over induced seismic activity in both stages. Lastly, to overcome limitations in current Mmax forecasting models, a hybrid model Y24, integrating the advantages of four forecasting models, was proposed, demonstrating higher accuracy and reliability in forecasting during both hydraulic fracturing and post-closure stages. The study's findings provide crucial technical support and decision-making basis for the seismic risk management of EGS projects or shale gas development projects employing hydraulic fracturing, underscoring their significance in ensuring the safety and sustainability of new energy and resource development endeavors.

The injection capacity evaluation of high-pressure water injection in low permeability reservoir: numerical and case study

Low permeability oil reservoir resources are rich and their efficient development is considered an important way to solve energy security issues. However, the development process of low permeability oil reservoirs is faced with the challenges of insufficient natural energy and rapid production decline. The high-pressure water injection technology is a method that relies on high-pressure and large-volume to inject fluid into the reservoir to replenish energy. It is considered as an important technical means to quickly replenish formation energy. This study focuses on the injection capacity for the high-pressure water injection technology of low permeability oil reservoir. Firstly, the fluid-structure interaction mathematical model for two-phase fluid flow was established. The solution of the mathematical model was then obtained by coupling the phase transport in porous media module and Darcy’s law module on the COMSOL numerical simulation platform. The numerical model established in this study was verified through the Buckley-Leverett model. The study on the injection capacity of high-pressure water injection technology was conducted using the geological background and reservoir physical properties of Binnan Oilfield (Shengli, China). The results show that the production pressure difference is the key factor in determining the injection capacity. When the production pressure difference increases from 5 MPa to 30 MPa, the cumulative injection volume increases by 8.1 times. In addition, sensitivity analysis shows that the injection capacity is significantly influenced by the properties of the reformation area. The effect of these parameters from high to low is as follows: stress sensitivity factor, permeability, rock compressibility, and porosity. Compared to the reformation area, the influence of the physical parameters of the matrix area on the injection capacity is negligible. Therefore, effective reservoir reformation is essential for enhancing the injection capacity. This research provides a theoretical basis for the design and optimization of the high-pressure water injection technology schemes for low permeability oil reservoir.

Surface Deformation and Seismicity Linked to Fluid Injection in the Raton Basin.

It is suggested that in addition to seismicity deep fluid injection may cause surface uplift and subsidence in oil and gas-producing regions. This study uses the Raton Basin as an example to investigate the hydromechanical processes of surface uplift and subsidence during wastewater injection. The Raton Basin, in southern central Colorado and northern central New Mexico, has experienced wastewater injection related to coalbed methane and gas production starting in 1994. In this study, we estimate the extent and magnitude of total vertical deformation in the Raton Basin from 1994 to 2020 and incremental deformation between the years 2017 to 2020. Results indicate a modeled uplift as much as 15 cm occurring between 1994 and 2020. Between 2017 and 2020, up to 3 cm of uplift occurred, largely near the northwestern injection wells. Most modeled uplift between 1994 and 2020 occurred near the southern wells, where the greatest cumulative volume of wastewater was injected. However, modeled subsidence occurred around the southern and eastern wells between 2017 and 2020, after the rate of injection decreased. Modeling indicates that while the magnitude of modeled uplift corresponds to cumulative injection volume and maximum rate in the long-term, short-term incremental deformation (uplift or subsidence) is controlled by changes in the rate of injection. The number of yearly earthquake events follows periods of rapid modeled uplifting throughout the Basin, suggesting that measurable surface deformation may be caused by the same injection-induced pore pressure perturbations that initiate seismicity.

ANALISA KERUSAKAN FORMASI PADA SUMUR INJEKSI H-01, H-02, H-03 & H-04 MENGGUNAKAN METODE HALL PLOT PADA LAPANGAN KENARI

Water injection is one of the secondary recovery stages used to increase oil and gas production. In its application, injected water is prone to cause problems such as damage to the formation, therefore it is necessary to analyze, including using the Hall Plot method. The Hall Plot method is a curve plotted based on cumulative pressure against cumulative injection volume, where this method is used to identify what the actual condition of the injection well is. From the results of the analysis and calculations that have been carried out on the four injection wells, one of them is experiencing formation damage, namely the H-01 well, as seen from the results of the calculation of the Skin factor from the Darcy and Hall Plot formulations showing a value of +32.011 and +64.562 and the value of the Injectivity Index is 2.026 bbl/day/Psi. Wells that have been identified as damaged are then analyzed for stimulation feasibility. From the results of the stimulation feasibility analysis in the form of injection water quality analysis and calculations, it is recommended that the H-01 well be matrix acidizing

Optimization of the Algorithm for Increasing Injection Rate in Water Injection Wells for Pressure Optimization in P Oilfield

In today’s society, with the continuous growth of energy demand, Bohai Oilfield, as an important offshore oil resource base in China, is facing increasingly severe challenges while contributing to national energy security. In order to improve the quality of water injection in the oilfield and gradually achieve efficient and stable production, Bohai Oilfield has launched a water injection well pressure optimization project, focusing on improving the efficiency and quality of water injection in the water injection wells, in order to achieve the optimal water injection plan. In practical work, P Oilfield continues to promote the development of water injection well pressure optimization projects, emphasizing practical exploration and continuous optimization of work plans. However, during the project implementation process, there were some problems, one of which was that the statistics of cumulative injection volume were not scientific enough, resulting in a more comprehensive and accurate presentation of the actual results of pressure optimization work. In the context of continuous improvement work, after careful analysis and research, P Oilfield has decided to optimize the cumulative injection rate algorithm to guide the oilfield’s water injection work in a more refined way, ensuring sufficient and good water injection, and enhancing the oilfield’s production efficiency and comprehensive competitiveness.

A robust deep learning workflow to predict multiphase flow behavior during geological [formula omitted] sequestration injection and Post-Injection periods

Simulation of multiphase flow in porous media is essential to manage the geologic CO2 sequestration (GCS) process, and physics-based simulation approaches usually take prohibitively high computational cost due to the nonlinearity of the coupled physics. This paper contributes to the development and evaluation of a deep learning workflow that accurately and efficiently predicts the temporal-spatial evolution of pressure and CO2 plumes during injection and post-injection periods of GCS operations. Based on a Fourier Neural Operator, the deep learning workflow takes input variables or features including rock properties, well operational controls and time steps, and predicts the state variables of pressure and CO2 saturation. To further improve the predictive fidelity, separate deep learning models are trained for CO2 injection and post-injection periods due to the difference in primary driving force of fluid flow and transport during these two phases. We also explore different combinations of features to predict the state variables. We use a realistic example of CO2 injection and storage in a 3D heterogeneous saline aquifer, and apply the deep learning workflow that is trained from physics-based simulation data and emulate the physics process. Through this numerical experiment, we demonstrate that using two separate deep learning models to distinguish post-injection from injection period generates the most accurate prediction of pressure, and a single deep learning model of the whole GCS process including the cumulative injection volume of CO2 as a deep learning feature, leads to the most accurate prediction of CO2 saturation. For the post-injection period, it is key to use cumulative CO2 injection volume to inform the deep learning models about the total carbon storage when predicting either pressure or saturation. The deep learning workflow not only provides high predictive fidelity across temporal and spatial scales, but also offers a speedup of 250 times compared to full physics reservoir simulation, and thus will be a significant predictive tool for engineers to manage the long-term process of GCS.

Spatiotemporal Analysis of Seismotectonic State of Injection‐Induced Seismicity Clusters in the Western Canada Sedimentary Basin

AbstractThe observations of spatiotemporal distribution of seismicity in western Canada indicate that the occurrence of earthquakes is tied to the hydraulic fracturing operations and disposal of coproduced wastewater. In this study, we investigate the temporal changes in the frequency‐magnitude distributions for multiple clusters of induced events in regions where the level of background seismicity is low. The induced events are clustered into six major groups using density‐based spatial and soft clustering algorithms based on their epicenters. Each cluster is identified by different distributions of earthquake magnitudes and injection scenarios. The linear relationship between the number of induced earthquakes and cumulative injection volume enables us, on a regional scale, to quantitatively characterize the seismotectonic conditions of the clusters using the estimates of the seismogenic indices. The seismogenic index provides a means to estimate the occurrence probability of earthquakes with a given magnitude induced during injection. The calculated seismogenic indices agree very well with the expected seismic response to hydraulic fracturing and wastewater disposal and show a strong correlation with tectonically accumulated strain energy. Statistical models based on the seismogenic index can be employed to mitigate the potential risk of large magnitude induced events.

Hydraulic fracturing for improved nutrient delivery in microbially-enhanced coalbed-methane (MECBM) production

Microbially enhanced coalbed methane (MECBM) recovery is a novel method to increase gas production by injecting nutrients, either with/without microorganisms, in depleted CBM wells. However, to be effective, methanogens require that the nutrient must be delivered efficiently by aqueous solution to a maximally large reservoir volume for microbial colonization. This study seeks to improve understanding of solute transport and microbial gas generation in naturally fractured reservoirs that are both pristine and hydraulically fractured. We complete a field-scale numerical simulation using an equivalent multi-continuum method to define the effectiveness of nutrient delivery. The complex pre-existing fracture pattern in the coalbed is represented by an overprinted discrete fracture network (DFN) to capture the natural heterogeneity and anisotropy of fracture permeability. A simplified PKN model is adopted to simulate hydraulic fracture propagation based on linear elastic fracture mechanics (LEFM). The hydraulically stimulated case is compared to the untreated control case, both without and with a network of natural fractures. Saturated cleat area, cumulative injection volume and prediction of methane yields are systematically modeled and analyzed for all three cases. We show that hydraulically stimulated fracture pathways, especially when connecting with a natural fracture network, optimally deliver nutrient remotely from the injection well, thereby increasing nutrient delivery and improving methane production and potential recovery. However, large magnitudes of proppant embedment and related permeability loss in the hydraulic fractures may reduce MECBM recovery. In the optimal production scenario, the methane production rate may reach 31 ft3/ton, an approximately 5-fold increase over that from the pristine unstimulated case.

Effect of Polymer Degradation on Polymer Flooding in Heterogeneous Reservoirs.

Polymer degradation is critical for polymer flooding because it can significantly influence the viscosity of a polymer solution, which is a dominant property for polymer enhanced oil recovery (EOR). In this work, physical experiments and numerical simulations were both used to study partially hydrolyzed polyacrylamide (HPAM) degradation and its effect on polymer flooding in heterogeneous reservoirs. First, physical experiments were conducted to determine basic physicochemical properties of the polymer, including viscosity and degradation. Notably, a novel polymer dynamic degradation experiment was recommended in the evaluation process. Then, a new mathematical model was proposed and an in-house three-dimensional (3D) two-phase polymer flooding simulator was designed to examine both polymer static and dynamic degradation. The designed simulator was validated by comparison with the simulation results obtained from commercial software and the results from the polymer flooding experiments. This simulator further investigated and validated polymer degradation and its effect. The results of the physical experiments showed that the viscosity of a polymer solution increases with an increase in polymer concentration, demonstrating their underlying power law relationship. Moreover, the viscosity of a polymer solution with the same polymer concentration decreases with an increase in the shear rate, demonstrating shear thinning. Furthermore, the viscosity of a polymer solution decreased with an increase in time due to polymer degradation, exhibiting an exponential relationship. The first-order dynamic degradation rate constant of 0.0022 day−1 was greater than the first-order static degradation rate constant of 0.0017 day−1. According to the simulation results for the designed simulator, a 7.7% decrease in oil recovery, after a cumulative injection volume of 1.67 pore volume (PV) was observed between the first-order dynamic degradation rate constants of 0 and 0.1 day−1, which indicates that polymer degradation has a detrimental effect on polymer flooding efficiency.

Prognosis for Safe Water-Disposal-Well Operations and Practices That Are Based on Reservoir Flow Modeling and Real-Time Performance Analysis

Summary Oklahoma has been at center stage of induced seismicity. Water-disposal activities have been associated with triggering the increasing number of seismic events. The objective of the study is to provide a simple diagnostics method and procedure for safe water-disposal operations. A comprehensive suite of scenarios and parameters has been analyzed that affect water disposal. On the basis of this study, prognosis will lead to safe water-disposal operation without the adverse effect. A suite of reservoir models involving water injection helped understand disposal-well performance. The well operational limits correspond to disposal-zone fracture gradient. The modified Hall analysis is used to ascertain the point of departure from normal injection behavior. Limiting cumulative injected volumes are determined and investigated for various scenarios from simple to increasingly complex subsurface conditions. This investigation includes studying the effects of disposal-zone porosity, compartment size, conductivity, formation compressibility, heterogeneity, and natural fractures. In addition, we explored the effects of communication with overlying producing zone, communication through completion anomaly, seal integrity, and fluid complexities. This study illuminates an overall understanding of disposal-well performance through various scenario analyses. A relationship between disposal-zone fracture gradient and limiting cumulative injection volume is established. For a fracture gradient of 0.7 psi/ft, this limiting pore-volume (PV) injection is less than 2%, which corresponds well with the conventional wisdom learned from carbon dioxide (CO2) injection-well performance. The relationship of disposal-zone compartment size, established with rate-transient analysis (RTA), with limiting cumulative injection volume is formulated. Analyses from the various statistical design of experiments (DoEs) reveal the important variables that may affect disposal-well performance. The disposal-well operation can be devised in real time with the modified Hall analysis that can reveal the departure from normal injection-well behavior. Factors accentuating the departure from normal behavior include disposal-zone porosity, formation compressibility, and seal integrity. Situations in which pressure release through leaks or communication with an adjacent formation takes place will naturally accommodate a larger volume of disposal water. Also, we learned that limiting cumulative injection volume and not injection rate (assuming injection pressure gradient is less than the fracture gradient) triggers a departure from normal injection behavior. Using a suite of numerical reservoir models and the reservoir-monitoring tools involving modified. Hall analysis and RTA led to a comprehensive understanding of disposal-well performance. This study found a relationship of fracture gradient with limiting cumulative injection volume, and identified key variables affecting the disposal-well behavior. These findings led to a smart and safe disposal-well monitoring scheme, which will help disposal-well management become more economical and environmentally friendly.

A new method for evaluating the injection effect of chemical flooding

Hall plot analysis, as a widespread injection evaluation method, however, often fails to achieve the desired result because of the inconspicuous change of the curve shape. Based on the cumulative injection volume, injection rate, and the injection pressure, this paper establishes a new method using the ratio of the pressure to the injection rate (RPI) and the rate of change of the RPI to evaluate the injection efficiency of chemical flooding. The relationship between the RPI and the apparent resistance factor (apparent residual resistance factor) is obtained, similarly to the relationship between the rate of change of the RPI and the resistance factor. In order to estimate a thief zone in a reservoir, the influence of chemical crossflow on the rate of change of the RPI is analyzed. The new method has been applied successfully in the western part of the Gudong 7th reservoir. Compared with the Hall plot analysis, it is more accurate in real-time injection data interpretation and crossflow estimation. Specially, the rate of change of the RPI could be particularly suitably applied for new wells or converted wells lacking early water flooding history.

Maximum magnitude estimations of induced earthquakes at Paradox Valley, Colorado, from cumulative injection volume and geometry of seismicity clusters

The Paradox Valley Unit (PVU), a salinity control project in southwest Colorado, disposes of brine in a single deep injection well. Since the initiation of injection at the PVU in 1991, earthquakes have been repeatedly induced. PVU closely monitors all seismicity in the Paradox Valley region with a dense surface seismic network. A key factor for understanding the seismic hazard from PVU injection is the maximum magnitude earthquake that can be induced. The estimate of maximum magnitude of induced earthquakes is difficult to constrain as, unlike naturally occurring earthquakes, the maximum magnitude of induced earthquakes changes over time and is affected by injection parameters. We investigate temporal variations in maximum magnitudes of induced earthquakes at the PVU using two methods. First, we consider the relationship between the total cumulative injected volume and the history of observed largest earthquakes at the PVU. Second, we explore the relationship between maximum magnitude and the geometry of individual seismicity clusters. Under the assumptions that: (i) elevated pore pressures must be distributed over an entire fault surface to initiate rupture and (ii) the location of induced events delineates volumes of sufficiently high pore-pressure to induce rupture, we calculate the largest allowable vertical penny-shaped faults, and investigate the potential earthquake magnitudes represented by their rupture. Results from both the injection volume and geometrical methods suggest that the PVU has the potential to induce events up to roughly MW 5 in the region directly surrounding the well; however, the largest observed earthquake to date has been about a magnitude unit smaller than this predicted maximum. In the seismicity cluster surrounding the injection well, the maximum potential earthquake size estimated by these methods and the observed maximum magnitudes have remained steady since the mid­ 2000s. These observations suggest that either these methods overpredict maximum magnitude for this area or that long time delays are required for sufficient pore-pressure diffusion to occur to cause rupture along an entire fault segment. We note that earthquake clusters can initiate and grow rapidly over the course of 1 or 2 yr, thus making it difficult to predict maximum earthquake magnitudes far into the future. The abrupt onset of seismicity with injection indicates that pore-pressure increases near the well have been sufficient to trigger earthquakes under pre-existing tectonic stresses. However, we do not observe remote triggering from large teleseismic earthquakes, which suggests that the stress perturbations generated from those events are too small to trigger rupture, even with the increased pore pressures.

Methods for estimating CO2 storage in saline reservoirs

Abstract Methods for estimating subsurface volumes in porous and permeable geologic formations are routinely applied in oil and gas, ground water, underground natural gas storage, and UIC disposal evaluations. In general, these methods can be divided into two categories: static and dynamic. The static models require only rock and fluid properties, while the dynamic methods require information about active injection, e.g. injection volumes and reservoir pressures. The static models are volumetric and compressibility; the dynamic models are decline curve analyses, mass (or volumetric) balance, and reservoir simulation. The volumetric method requires a simple geometric description of the formation that includes formation height and area, porosity, and some type of factor that reflects the pore volume that CO2 can occupy. The compressibility method relates the change in pore pressure to the change in water and pore volume. Pore pressure will increase as CO2 is injected. This causes a decrease in water volume and an increase in pore volume. The sum of these changes can accommodate space for CO2 storage. This is primarily an issue for closed reservoirs. For active CO2 injection, in addition to the static methods, dynamic methods can be used. Some geologic formations will incur flat or constant injection rates with variable injection pressure, while other formations will have decreasing injection rate with constant injection pressure. This is primarily due to surface operations and the outer boundary condition of the reservoir (closed or open). A decreasing injection rate trend can be analyzed and extrapolated to an uneconomic injection rate to infer the ultimate storage capacity of an active injection well. Mass or volumetric balance can be used to estimate subsurface injected volumes using cumulative injection volume as a function of pore pressure. Based on the geologic unit, combinations of parameters are used to allow straight line projections of the observed trends to make forecasts of the ultimate storage capacity. Injection zone flow simulation models can be used pre- or post injection, require the most input data and can accommodate a very rigorously defined geologic model. Storage estimates can be made readily from simulation for various development scenarios that include completion interval, well-type, injection rates, and multiple injection well spacing. The data requirements, assumptions and limitations for each of these methods are reviewed. Advantages and disadvantages of applying each method to basin-scale and specific site-scale storage estimates are discussed.

Pulse Dampener for Coreflood Experiments

Summary A pulse dampener that significantly reduces the fluctuations frequently present in the flow from reciprocating piston pumps is described. Frequency-response methods are used to design the pulse dampener. A design procedure is presented to enable one to design the pulse dampener for the particular experimental situation of interest. This pulse dampener is effective when the pressure drop across the experimental system changes with time as well as when it is constant. The pulse dampener is also compact inexpensive and easy to construct. "The first step in the design is to examine the pump to determine the frequency and amplitude of the fluctuations in the flow." Introduction Positive-displacement pumps are used extensively in research laboratories. Typical applications include liquid chromatography, kinetic experiments, filter design, and flow experiments on core samples from petroleum reservoirs. A constant flow rate is usually desired for purposes of analysis of experimental data. Syringe-type pumps are generally able to achieve this constant flow rate. One disadvantage of syringe pumps is that the cumulative injection volume is limited by the volume of the syringe and for many applications it is undesirable to stop the experiment to refill the syringe. For this and other reasons, pumps of the reciprocating-piston type are often used. Mechanical features of such pumps typically cause cyclic fluctuations in the flow from the pumps. For pumps with small pistons, and thus frequent reversals, these fluctuations can be as much as several percent of the nominal flow rate and can be an important error source when parameters in a mathematical model of the experiment are estimated from experimental data. An example is the estimation of relative permeability curves from laboratory displacement data on a porous rock sample. At a microscopic level, the displacement of one fluid by another in a porous medium is a function of local pore geometry and fluid pressures. Oscillations in the injection flow rate will cause local pressure oscillations. In turn, fluid may be displaced from individual pores at times that would be different from those for pulse-free injection. Furthermore, pressure oscillations may give rise to hysteresis effects. Such local phenomena are not represented in the macroscopic model used to represent the experiment in the process of estimating the relative permeability parameters. Thus, pulsing flow could be a source of error in estimating those parameters, the magnitude of which is not easily estimated. In situations for which derivatives of measured data are used in the estimation process, flow fluctuations may be a significant error source in parameter estimates because measurement noise is amplified in the differentiation process. Flow fluctuations can be reduced by use of a pulse dampener. We consider here a pulse dampener that is constructed of a fluid capacitance in series with a fluid resistance, as shown in Fig. 1. The accumulator initially filled with gas) acts as the fluid capacitance, with the coil of capillary tubing and the experimental system providing the fluid resistance. An expandable diaphragm, or bellows, separates the gas from the liquid in the accumulator. A backpressure regulator (which can be omitted) is included in this diagram and in the subsequent analysis as well. Because the accumulator may be operating at high pressure, it should be equipped with a pressure-relief valve and constructed of suitable materials. This pulse dampener works in the following manner. Changes in the pump flow rate correspond to changes in pressure. As the pressure of the stream coming out of the pump changes, the gas volume inside the accumulator expands and contracts, accepting fluid when the pump flow rate (and hence the pressure) increases and releasing fluid when the pump flow rate decreases. If the flow characteristics (i.e., the relationship between pressure drop and flow rate) of the experimental system do not change with time, then the gas volume will oscillate about a constant value. However, if the pressure drop across the experimental system changes with time (as in most coreflood experiments) and if this change significantly affects the pressure on the accumulator, then the gas volume will also show bulk changes over time. In this case, the flow rate through the experimental system will be smooth but not constant, an undesirable result. This problem is solved in the present system by using a sufficient length of capillary tubing and/or a sufficiently high backpressure so that the variation of the pressure drop across the experimental system is negligible compared with the pressure on the accumulator. In this paper, we show that the performance of this pulse dampener can be described mathematically by a nonlinear, first-order ordinary differential equation. A frequency-response approach is used to develop design criteria for the pulse dampener, taking into account the specific characteristics of the pump and the experimental apparatus. P. 986^