Location Of Injection Wells Research Articles

Improvement of well drainage radius calculation

The calculation of well drainage radius is improved on the example of Chervonozayarske gas field. Theoretical research methods are applied, which include a systematic analysis of the information used, numerical modeling based on the combined finite element-difference method, methods of visual representation of the information obtained, analytical methods To increase the accuracy of the calculation of the well drainage radius, the heterogeneity of the porous medium structure was taken into account. It is established that the drainage radius of a gas well expands with time. This allows to determine the optimal grid of production wells, the number and location of injection wells to ensure their interaction, and hence ¬ reduce material costs in the gas industry

Locating optimal position of artificial recharge wells in aquifer using grey wolf optimization algorithm and isogeometric numerical method

The construction of injection wells is one of the direct methods of artificial recharge and determining their optimal location is one of the important issues that are discussed in the topics of projects related to the rehabilitation of aquifers. In this research, a simulation–optimization model was proposed to determine the optimal location of injection wells using the Isogeometric analysis (IGA) numerical model and the Grey wolf optimization algorithm (GWO). In this regard, first, a groundwater model based on Isogeometric analysis was created to simulate groundwater flow in a hypothetical aquifer. Finally, after ensuring the accuracy of the simulator model, the optimal location of 10 injection wells was evaluated under two scenarios based on different values of hydraulic conductivity and specific yield. The accuracy of the simulation model is computed based on three error criteria ME, MAE and RMSE were the evaluation criteria which equaled −0.96%, 1.11%, and 0.0146 m, respectively. The achieved results showed that the Isogeometric analysis model has high accuracy. The results of the IGA-GWO model indicated that after constructing injection wells in the optimal location, the groundwater table on average in 10 injection wells rises more than 50 cm in both scenarios. The results also showed that due to the change in aquifer hydraulic conductivity and specific yield in different regions and the defined boundary conditions in the problem, the optimal location of injection wells are in regions with more hydraulic conductivity and more specific yield. Also, injection in regions with more drops will increase the groundwater table.

Fresh-saline water dynamics in coastal aquifers: Sand tank experiments with MAR-wells injecting at intermittent regimes

Seawater intrusion (SWI) has been widely investigated in physical sandbox-field experiments and analytical–numerical mathematical models. However, to the best of our knowledge, there were no studies of a commingled dynamics of the triad of saline water, natural fresh groundwater and freshwater injected in managed aquifer recharge (MAR) using sand tank experiments similar to the one presented in this paper. The main objective of this research is to investigate the encroachment and retreat of saline water in a coastal unconfined aquifer under various MAR-injection schemes. The effectiveness of MAR in mitigating SWI is explored using sand tank experiments under a spectrum of hydrological conditions that include various locations-depths of injection wells, including injection and post-injection evolution of the fresh and saline lenses-bubbles, when a pulse of treated wastewater (TWW) was inoculated into an initially static dense sea water tongue. Regimes (volumes) of freshwater jabs were also varied in our experiments. Our essentially transient flows showed that injecting water close to the toe of a “background” saltwater-freshwater interface was more effective to reduce SWI by 32% to 61.4% (depending on the injected volume, which varied from 0.5 L to 1.4 L), compared with the scenarios of wells placed away from the toe. Injection of water within the initially static saline water tongue (behind the interface) retarded the re-intrusion of saline water because the created “freshwater bubble” (topologically isolated from fresh groundwater) built an evanescent hydrological barrier against intrusion. Injection of water near the saline water boundary (SWB) and above the interface resulted in large direct loss of the injected water to the ocean, by seeping above the aquifer-intruded saline tongue, with only minimal impact on it. Injection at a shallow depth was more effective in reducing the salinity in the intruded zone of the aquifer compared with the scenario when the injection was performed deeper (near the bottom of the aquifer/sandbox). Injecting a larger volume has caused further recession of the saltwater-freshwater interface seawards (increasing the injected volume by 32%, the tip of the interface retreated by 43% more). However, our experiments showed that it is important to monitor the height of the created water table mound because a steeper hydraulic gradient in the “adverse” inland direction may provoke local farmers to pirate the injected water by dug-drilled illegal wells and creating an uncontrolled recovery, rather than a designed MAR-combatting, system. We monitored a rapid discharge (loss) of the injected water through both the vertical boundaries of the sand tank. In field MAR conditions when aquifer storage and recovery are practiced, abstraction wells can be the discharge (or drain) facility and so injection and abstraction rates should be strictly administered-balanced to increase the effectiveness of injection in mitigation of SWI. Optimization of MAR (by using the location of injection wells, rates and volumes of injection, depths of screens, duration of injection as control variables, along with maintaining the fresh water balance for the aquifer as a constraint) is necessary to avoid ineffectiveness or failure of MAR aimed at combating SWI.

Geologic CO2 Storage Optimization under Geomechanical Risk Using Coupled-Physics Models

Numerical simulation of fluid flow, transport, and trapping mechanisms have been used to optimize CO2 storage in geologic formations by improving trapping efficiency through injection strategies. Flow models, however, do not capture the geomechanical deformation that can occur during CO2 injection, including reservoir expansion, ground surface uplift, and induced seismicity. The geomechanical risks of CO2 injection have drawn more attention in recent years and coupled flow and geomechanical simulation models are increasingly used to study the geomechanical effects during CO2 injection, to ensure environmentally sound and safe operations. We present an optimization framework for geologic CO2 storage under geomechanical risks, where coupled flow-geomechanics simulations are used to quantify the risks of injection-induced ground surface deformation and rock failure in reservoir and caprock layers. A multi-objective optimization problem is formulated and solved to maximize CO2 storage while minimizing the two forms of geomechanical risks. The optimization decision variables include the locations of injection wells. Multiple numerical experiments with increasing complexity are presented to demonstrate the performance of the proposed framework. The results reveal optimal decisions that are different from those obtained from flow-only simulation that disregard the geomechanical risks associated with CO2 injection. When geomechanical risks are considered, the wells may not necessarily be concentrated in areas with the highest storage capacity because that may lead to rock failure and/or unacceptable levels of ground surface uplift. Overall, the observations from this study reveal important differences in optimization results and conclusions when geomechanical risks of geologic CO2 storage are considered.

Effects of reservoir size and boundary conditions on pore-pressure buildup and fault reactivation during CO2 injection in deep geological reservoirs

The excessive burning of the fossil fuels has caused severe global climatic changes such as increasing the global temperature, causing initiation of the wild fire, rising the sea level, increasing the floods, storms, amount of rain and snow. One of the effective global mitigation strategies is sequestration of huge quantity of CO2 deep below the ground level for a long period of time. An important issue is to ensure the permanency and safety of the sequestration process due to the associated pore-pressure buildup. It is necessary to have correct estimates of the pore-pressure buildup, ground uplift and re-activation of any existing fault during the process of CO2 injection and long-term storage. In this investigation, the effects of reservoir size and boundary conditions are investigated by means of geomechanical modeling of the deep Biyadh sandstone reservoir in Saudi Arabia. Currently, carbon dioxide is not injected into the actual Biyadh reservoir. In this investigative modeling, CO2 is injected for an injection period of ten years using a single injection well at the center of the reservoir. The developed modeling scheme for a single injection well has been extended further to include multiple injection wells. For multiple injection wells, the reservoir size and locations of injection wells are varied to evaluate their effect on the pore-pressure buildup and ground uplift. The reservoir stability analysis has been performed using Mohr–Coulomb failure criterion for both small and large reservoir models, with the same injection parameters. The simulation results demonstrated that pressure buildup and ground uplift are relatively higher for reservoirs with small sizes and closed boundaries; while in the case of large sizes and open boundaries, the pore-pressure buildup and ground uplift are relatively lower. Moreover, the effect of the reservoir size and boundary conditions on the reactivation of faults during CO2 injection has been evaluated. The stability analysis performed in this study shows that injecting CO2 into larger size reservoir is safer as compared to smaller size reservoir. Injecting CO2 with multiple injection wells will cause pore-pressure buildup of huge magnitudes. The modeling results show that suggesting a representative volume for the reservoir during CO2 injection can under-estimate the pore-pressure buildup and fault re-activation that can cause the reservoir failure and leakage of the stored CO2.

Patterns of recovery and injection wells in deposits of high-viscosity oil with reservoir decompression zones

The issue of patterns of injection and recovery wells in zones of non-uniform permeability reservoirs is discussed by many researchers. The researchers aim to identify the influence of well patterns in reservoir zones with different permeability on the efficiency of oil recovery. This issue is particularly acute for systems maintaining reservoir pressure. The location of injection wells in low-permeable zones, and recovery wells - in high-permeability zones helps increase the coverage of the impact. Moreover, even in the conditions of a partially developed reservoir, transformation of the existing development system has significant potencies for increasing the ORC. One more crucial problem is the study of the effect of extensive highly permeable inclusions (faults, zones of reservoir loosening) on the effectiveness of regular development systems.

Numerical simulation on heat extraction performance of enhanced geothermal system under the different well layout

China has hundreds of thousands of oil and water wells, about 30% of which have been abandoned currently. If we can convert abandoned wells into geothermal wells, it will save lots of money and reduce drilling and completion time greatly. In this paper, six enhanced geothermal system (EGS) well layout schemes are proposed based on the utilization of abandoned oil–water wells and common oilfield well pattern. Here six common injection-production well patterns in oilfield are combined to hot dry rock (HDR) production and the heat extraction performance is simulated. The results show that the injection well number and the location of injection wells have critical influence on the heat extraction performance. Under the same total injection mass flow rate, the injection well number is the key factor and the fracture area is the secondary factor on heat extraction when the HDR energy is enough. For electricity generation, the life span is 20.2, 19.2, 19.0, 19.2, 18.2 and 13.9 years, and the heat extraction ratio is 65.83, 57.35, 65.96, 62.79, 59.30 and 43.09% from case 1 to case 6, respectively. For heating demand, the life span is 30.0, 30.0, 29.9, 30.0, 29.8, and 27.7 years, the heat extraction ratio is 78.91, 69.63, 77.02, 75.92, 72.27 and 58.94% from case 1 to case 6, respectively. The total injection mass flow rate and injection temperature also have a negative effect on the heat extraction performance. Case 1 (row parallel well layout), Case 3 (four-spot well layout) and Case 4 (five-spot well layout) are a good choice both for electricity generation and heating demand. This study provides good guidance for the selection and optimization of different EGS well layout.

Seismicity Analysis and Velocity Structure of the Two-Phase Geothermal Field in West Java, Indonesia: Preliminary Result

We observed 754 microearthquake data by at least 15 stations for six months as a tool to monitor and characterize the subsurface condition in two-phase geothermal field in Southern Bandung. The data were reduced to 417 events having azimuthal gap less than 180°. We determine the initial earthquake locations in this study by using Geiger method and we update the hypocenter locations by performing simultaneous inversion for hypocenters and 1D velocity structure followed by 3D tomographic inversion. We obtained the velocity structure by utilizing TomoDD to perform 3D tomographic inversion. There are four clusters of seismicity observed in this study which we suspected related to the injection, production, and tectonic activity of the study area. The southern cluster is consistent with the location of injection wells and spread from 1 km depth to 8 km depth, indicating that MEQ events were triggered by injection activity. The production area is characterized by a denser population of events and the events were distributed closely ranging from 1 to 3 km depth. We suspect that the third cluster is caused by development activity of steam dominated geothermal field omit in the east of our main field. The fourth cluster is located in the southernmost of our area and suspected caused by tectonic activity. Low Vp/Vs values near to the surface are observed in the north direction and coincide with the location of the first cluster. The location of anomaly is highly corresponded with the production area and the low value of Vp/Vs anomaly is interpreted as the steam zone.

EFFICIENT LOCATION OF THE ROWS OF INJECTION AND PRODUCTION WELLS IN HIGH VISCOSITY OIL DEPOSITS WITH EXTENDED RESERVOIR TIGHTNESS ZONES

Background A lot of works are devoted to the issues of injection and production wells location in a zonal inhomogeneous permeable reservoir. Researchers are trying to understand how the location of wells in reservoir zones with different permeability affects oil recovery efficiency. This issue is particularly acute for development systems with maintaining reservoir pressure. It has been established that the location of injection wells in low-permeable zones, and production in the high-permeable zones of the reservoir contributes to increasing the coverage of the impact. Moreover, even in the conditions of a partially developed reservoir, the transformation of the existing development system according to the above principle has significant potencies for increasing the oil recovery factor (ORF). Another actual problem is the study of the effect of extensive high-permeable inclusions (faults, reservoir tightness zones) on the effectiveness of regular development systems. It is concluded that the development systems with different location of production and injection wells with regard to fault lines are unequal. This assumption requires not only qualitative, but also quantitative evaluation. Aims and Objectives: Consider the dependence of oil recovery on the location and orientation of the rows of production and injection wells with regard to fault lines. Results 1. It was established that the location of the rows of wells parallel to the fault line (variants 1, 2, 5, 6) allows to achieve a higher ORF compared to placing the rows of wells perpendicular to the fault line (variant 3). 2. Location a row of injection wells in the raised part of the reservoir is less effective than their location in the lower part. The most effective is the location of a row of production wells in the zone of decompression of the reservoir, and the rows of injection wells - outside the zone of decompression. This variant of well row location has the maximal withdrawal rate and the highest ORF value.

SBAS Analysis of Induced Ground Surface Deformation from Wastewater Injection in East Central Oklahoma, USA

The state of Oklahoma has experienced a dramatic increase in the amount of measurable seismic activities over the last decade. The needs of a petroleum-driven world have led to increased production utilizing various technologies to reach energy reserves locked in tight formations and stimulate end-of-life wells, creating significant amounts of undesirable wastewater ultimately injected underground for disposal. Using Phased Array L-band Synthetic Aperture Radar (PALSAR) data, we performed a differential Synthetic Aperture Radar Interferometry (InSAR) technique referred to as the Small BAseline Subset (SBAS)-based analysis over east central Oklahoma to identify ground surface deformation with respect to the location of wastewater injection wells for the period of December 2006 to January 2011. Our results show broad spatial correlation between SBAS-derived deformation and the locations of injection wells. We also observed significant uplift over Cushing, Oklahoma, the largest above ground crude oil storage facility in the world, and a key hub of the Keystone Pipeline. This finding has significant implications for the oil and gas industry due to its close proximity to the zones of increased seismicity attributed to wastewater injection. Results southeast of Drumright, Oklahoma represent an excellent example of the potential of InSAR, identifying a fault bordered by an area of subduction to the west and uplift to the east. This differentiated movement along the fault may help explain the lack of any seismic activity in this area, despite the large number of wells and high volume of fluid injected.

On the evaluation of steam assisted gravity drainage in naturally fractured oil reservoirs

Abstract Steam Assisted Gravity Drainage (SAGD) as a successful enhanced oil recovery (EOR) process has been applied to extract heavy and extra heavy oils. Huge amount of global heavy oil resources exists in carbonate reservoirs which are mostly naturally fractured reservoirs. Unlike clastic reservoirs, few studies were carried out to determine the performance of SAGD in carbonate reservoirs. Even though SAGD is a highly promising technique, several uncertainties and unanswered questions still exist and they should be clarified for expansion of SAGD methods to world wide applications especially in naturally fractured reservoirs. In this communication, the effects of some operational and reservoir parameters on SAGD processes were investigated in a naturally fractured reservoir with oil wet rock using CMG-STARS thermal simulator. The purpose of this study was to investigate the role of fracture properties including fracture orientation, fracture spacing and fracture permeability on the SAGD performance in naturally fractured reservoirs. Moreover, one operational parameter was also studied; one new well configuration, staggered well pair was evaluated. Results indicated that fracture orientation influences steam expansion and oil production from the horizontal well pairs. It was also found that horizontal fractures have unfavorable effects on oil production, while vertical fractures increase the production rate for the horizontal well. Moreover, an increase in fracture spacing results in more oil production, because in higher fracture spacing model, steam will have more time to diffuse into matrices and heat up the entire reservoir. Furthermore, an increase in fracture permeability results in process enhancement and ultimate recovery improvement. Besides, diagonal change in the location of injection wells (staggered model) increases the recovery efficiency in long-term production plan.

A generalized non-isothermal tank model for liquid dominated geothermal reservoirs

We present a generalized non-isothermal tank model for predicting the pressure and temperature behaviors of liquid dominated geothermal reservoirs. A geothermal system is represented by a single or multiple tanks. These tanks can represent the reservoir, multiple reservoirs, aquifers or any other component of a geothermal system. The mass and energy balance equations for each tank are solved jointly. One of the main advantages of the model is that only a small number of tanks are used for modeling which avoids over parameterization of a geothermal system and results in faster run times when compared with fully discretized numerical simulators. Synthetic examples are used for studying the effects of heat conduction on reservoir performance, an analysis of the location of injection wells, recovery times of depleted geothermal fields and the benefits of using temperature data for a better characterization of the geothermal system.

Geothermal reinjection experience

Reinjection into geothermal reservoirs is discussed and the experience gained by reinjection experiments in 44 geothermal fields is reviewed. Reinjection started purely as a disposal method, but has more recently been recognised as an essential and important part of reservoir management. Only a small part of the thermal energy in place in geothermal reservoirs can be recovered if reinjection is not applied. Thermal breakthrough has been observed in few geothermal reservoirs but has in all cases been found to be a manageable part of field operation. Silica scaling in surface equipment and injection wells is a delicate aspect of the reinjection process in most high-temperature geothermal fields, but silica scaling in the reservoir has not been considered a problem. Reinjection of low-enthalpy geothermal fluid into sandstone has not been successful, for reasons that are poorly understood. The location of injection wells in relation to production wells influences the ratio of injected fluid recovered in production wells. For peripheral injection, about one third of the injected fluid is commonly recovered, whereas injection within the production area results in a higher ratio of recovered fluid. Subsidence is in general of small concern in geothermal operations and micro-gravity has proved a valuable tool to estimate the recharge to geothermal reservoirs.