Maximum Allowable Injection Research Articles

Hydrogeological-geotechnical Characterization and Analysis for Construction of a Subsurface Reservoir at a Coastal Site in the Nakdong Deltaic Plain, Busan, South Korea

Store and recover clean groundwater from a man-made subsurface reservoir is useful for the development of coastal cities. A full-scale pilot field test of managed aquifer recharge (MAR) schemes were conducted in the Nakdong River plain, Korea. The process involved constructing a hydrogeological-geotechnical model based on investigation data, including the target aquifer that was located between 30 and 67 meters deep. The subsurface response to water pumping was analyzed, and this led to the creation of charts to determine the maximum allowable injection pressure and maximum recharge rate. For two factors of safety of 1.5 and 2.0, the maximum injection head rise was estimated to be 9.7 meters and 7.25 meters, respectively, corresponding to recharge rates of 5,000 and 3,800 m3/d. One-dimensional FE consolidation analyses were conducted for different groundwater drawdowns (2, 5, 10 and 15 m) and the results showed a good match with the monitored settlement and rebound for the 2-meter drawdown case. The study concluded that the injection rate could potentially be much higher than what was tested, which would increase the capacity of the subsurface reservoir. The lessons learned from this study are useful for similar coastal sites in terms of the application of MAR technology.

Pressure Modification or Barrier Issues during Polymer Flooding Enhanced Oil Recovery

Effective oil displacement from a reservoir requires adequate and properly directed pressure gradients in areas of high oil saturation. If the polymer bank is too large or too viscous during a polymer flood, the pressure drops from the injection well to the polymer front may act as a pressure modification or barrier by usurping most of the downstream driving force for oil displacement. Polymer injection pressures must be limited. The maximum allowable injection pressure is commonly constrained by caprock integrity, injection equipment, and/or regulations, even though fractures can be beneficial to polymer injectivity. This paper examines when the pressure-barrier concept limits the size and viscosity of the polymer bank during a polymer flood. Analytical and numerical methods are used to address this issue. We examine the relevance of the pressure modification concept for a wide variety of circumstances, including oil viscosities ranging from 10 cp to 1650 cp, vertical wells versus horizontal wells, single versus multiple layered reservoirs, permeability contrast, and crossflow between layers. We also examine the relation between the pressure-barrier concept and fractures and fracture extension during polymer injection. We demonstrate that in reservoirs with single layers, the pressure-barrier concept only limits the optimum viscosity of the injected polymer if the mobility of the polymer bank is less than the mobility of the displaced oil bank. The same is true for multizoned reservoirs with no crossflow between layers. Thus, for these cases, the optimum polymer viscosity is likely to be dictated by the mobility of the oil bank, unless other factors intervene. For multizoned reservoirs with free crossflow between layers, the situation is different. A compromise must be reached between injected polymer viscosity and the efficiency of oil recovery. This work is particularly relevant to viscous oil reservoirs where polymer viscosities are substantially lower than the oil viscosity.

Critical rate analysis for CO2 injection in depleted gas field, Sarawak Basin, offshore East Malaysia

This study aimed to address the challenges and strategies to determine the critical rate of CO2 injection into a carbonate depleted gas field. In this research, the critical rate is the maximum allowable injection rate before formation damage initiation. The cause of formation damage could be due to in-situ mobilization or trapping of migratory fines resulting in plugging the flow path. This study performed a thorough investigation of a different rock-fluid system to evaluate the safe injection limit, as the critical rate is different for each rock-fluid system. The geochemical effect of CO2 injection toward carbonate formation was also investigated in this research. Other than that, the porosity and permeability changes due to CO2-brine-rock multiphase flow characteristics were considered to understand the feasibility of CO2 sequestration into carbonate formation. This research discussed experimental design to mimic the CO2 injection scenario of CO2 into carbonate depleted gas field. Therefore, several core flooding experiments were conducted under reservoir conditions using representative native cores, CO2, and synthetic formation brine. Abrupt changes in differential pressure (ΔP), analysis of effluent collected after CO2 multi-rate flow, and pH reading are the key indicators to consider that the condition has reached a critical rate. The experimental result demonstrated the existence of fines migration, scale formation, and salt precipitation after the core was subjected to supercritical CO2 multi-rate flow. Considering these issues and challenges associated with injectivity, this study recommended a maximum injection rate prior to field scale injection.

Coupled Flow/Geomechanics Modeling of Interfracture Water Injection To Enhance Oil Recovery in Tight Reservoirs

Summary Unconventional tight reservoirs that are typically characterized by low permeability and low porosity have contributed significantly to the global hydrocarbon production in recent years. Although hydraulic fracturing, along with horizontal well drilling, enables the economic development of such reservoirs, the production rate often declines sharply and results in low primary hydrocarbon recovery. The application of enhanced-oil-recovery (EOR) techniques in tight reservoirs has received much interest. In this study, the feasibility and efficiency of interfracture water injection to enhance oil recovery in multistage fractured tight oil reservoirs are analyzed through an efficient coupled flow/geomechanics model with an embedded discrete-fracture model (EDFM). A combined finite-volume/finite-element scheme is used to discretize the governing equations for flow and geomechanics, and the coupled problem is solved sequentially using a fixed-stress splitting algorithm. A basic numerical model consisting of a 15-stage fractured horizontal well is constructed using the petrophysical and geomechanical properties of a tight oil formation in Ordos Basin, China. Fractures indexed with even numbers are switched into injecting fractures when the production rate has dropped to less than a certain threshold. The improvement of oil recovery is analyzed by comparing the production profiles with and without water injection. In this coupled model, the fracture closure/opening during production/injection is considered according to the constitutive relations between fracture aperture and effective normal stress acting on the fracture faces. The poromechanical response of matrix is modeled by the Biot (1941) theory. The effects of fracture spacing, injection rate, and the presence of a natural-fracture network on oil-recovery enhancement are discussed through sensitivity analysis. The main mechanisms of interfracture water injection for enhancing oil recovery are waterflooding and reservoir-pressure maintenance. Small fracture spacing tends to reduce the oil recovery because of fracture interference and a limited drainage area; therefore, the primary depletion stage is shortened as the fracture spacing is reduced. The influence of interfracture water injection is more pronounced with smaller fracture spacing because the pressure-transient responses near the producing fractures are more dramatic considering the close proximity between the injecting fracture and the producing fracture. Although a higher injection rate results in higher oil recovery, the injectivity in low-permeability reservoirs limits the maximum-allowable injection rate. When secondary (natural)-fracture networks are considered, neighboring hydraulic fractures can be connected to one another via the secondary fractures, particularly if the interfracture spacing is small. Water can break through in the producing fractures quickly, which could also lead to high water cut and suboptimal oil-recovery performance. This study tests the feasibility and efficiency of interfracture injection to enhance tight oil recovery. The results indicate that interfracture injection can be a promising EOR technique for tight oil reservoirs, which sheds lights on future completion strategies and production design in tight reservoirs.

Feasibility study of gas injection in low permeability reservoirs of Changqing oilfield

Changqing is the largest petroleum-producing field in China and one-third of its production is attributed to the formations with permeability lower than 1 mD. Based on the recent successes of gas injection pilots in North America, we investigated the feasibility of gas injection in the low permeability Chang 63 reservoir of Changqing. An eight-component fluid characterization, which fitted the measured PVT data, was used in a dual-porosity compositional model. A typical well pattern was selected for the simulation study. The key input parameters were adjusted to match the historical data. Huff-n-Puff using different gases shows that the richer the injected gas, the higher the oil production. C3H8 huff-n-puff achieves the best performance, increasing the cumulative oil production by a factor of 2.28 after 5 cycles, then followed by C2H6 and the produced gas. CH4 demonstrates a lower recovery factor (RF) than waterflood, because its minimum miscibility pressure is close to the maximum allowable injection pressure, i.e., the minimum horizontal stress. With the current well placement design where the producer is at the reservoir top, the miscible bank, which forms at the front of lean gas injection, will be displaced towards the reservoir bottom even out of the stimulated reservoir volume (SRV), undermining its performance. Rich gas is more compatible, as the miscible bank forms at the injection tail. Based on the fracture spacingsfrom the published work, we could, for the first time, verify the technical feasibility of rich gas injection in Chang 63 following the presented compositional modeling framework.

Fabrication and evaluation of nanostructured microelectrodes for high-spatial resolution in retinal prostheses

To provide visual information to patients with retinal degenerative disease, retinal prosthetic devices based on multi-channel microelectrode arrays (MEAs) have shown some promising results. For high-quality information, the number of microelectrodes should be increased in the limited area of MEAs, which results in decreased dimensions of the single microelectrode and a limit of dynamic range of injection current. Previously, our research group has presented 3D microelectrodes to overcome the trade-off between high-spatial resolution and injection current range. However, the 3D microelectrode requires a complex fabrication process, including multiple steps in front-side and back-side microfabrication. In this paper, the nanostructured microelectrode with platinum-black is fabricated with a simple process, and its electrical characteristics are evaluated. The nanostructured microelectrode parameters are analyzed by a conventional three-element circuit model. The comprehensive electrical characteristics between planar 2D, 3D, and nanostructured microelectrodes with various base areas are compared by measuring electrode–electrolyte interface impedance and maximum allowable injection current limit. The experimental results show improved interface impedance in nanostructured microelectrodes compared to planar 2D and 3D microelectrodes with same base area. This implies that nanostructured microelectrodes have a large dynamic range for current stimulation, which can be more sufficient in retinal neuron stimulation. This research can be used to estimate the theoretical limit of injection current for high-resolution MEAs.

CO2 adsorption the numerical simulations and the controlling factors to low rank coal

Carbon Capture Sequestration (CCS) in unmineable coal seams questionably gives benefits for the commercial success through potential release of additional methane during the injection of CO2 adsorbs into the coal seams, the process known as enhanced coalbed methane (ECBM) recovery. However, a significant concern lies in the loss of injectivity due to reduction in permeability by coal matrix swelling occurences with CO2 adsorption although this effect can be partially be offset with ‘huff and puff’ scheme of cyclic CO2 injection followed by extraction of the released methane. The paper discusses the results of a numerical simulation study carried out with GEM compositional reservoir simulator to evaluate the effects of uncertainties in various reservoir parameters on the overall volume of CO2 storage and additional methane recovery of low rank coalfield. A 12-15m thick seam at shallow depth, 50-75 m was considered for fluid flow simulation study. While some information on the reservoir setting was obtained through literature and personal communication with the CBM operators, the rest of the information was derived through laboratory studies. The reservoir parameters considered for the study are injection pressure, adsorption capacity, cleat permeability and porosity, and initial gas saturation. A 100-acre drainage area with 5-spot vertical well pattern was considered with one central injector and four producers on four corners of the study area. The maximum allowable injection pressure was estimated to be 7500 kPa at the reservoir setting. The injection pressure was varied from 1000 kPa to 7500 kPa in the simulation. A number of adsorption isotherms were established in the laboratory. The variations in the adsorption parameters observed through the isotherms were considered as uncertainty in the storage capacities. Significant variations were observed due to the variation in adsorption isotherms both for CO2 storage and additional methane recovery. Fracture permeability was varied from 3 md to 200 md, which is the range of permeability observed in the coalfield is around 100-200 mD. The results of simulation indicate a strong influence of porosity on the CO2 storage and ECBM recovery. Fluid flow simulation study shows that variation in sorption time has no significant effect for a low permeability situation while some marginal effect in high permeability situation. Cleat porosity was varied from 1 % to 10 %. Within this range of porosities, enhanced methane recovery varied from 1 % to 10 % relative to the primary recovery but the volume of stored CO2 did not vary significantly. Lastly, the pore pressure, adsorption and gas saturation of CO2 sequestered volume and additional methane recovery were found to increase substantially.

Preliminary Understanding of CO2 Sequestration and Enhanced Methane Recovery in Raniganj Coalfield of India by Reservoir Simulation

India has a vast reserve of coal (∼ 7% of the world's total proved reserve) and is the third largest producer in the world. Almost 70% of the country's electrical power comes from the coal-fired thermal power plants. A few coalbed methane (CBM) projects have also commenced operations in the central and eastern parts of the country. However, CO2 sequestration especially in geological formations is still at conceptual stage in India. Raniganj coalfield, located in the eastern states of West Bengal of Jharkhand is a repository of large reserves of high-volatile bituminous coals, where both mining and CBM operations are present. A number of coal-based thermal power plants are also located in the area, making this one of the most suitable areas for starting a carbon capture and storage (CCS) pilot project.CCS in unmineable coal seams arguably has the advantage of commercial success through potential release of additional methane when injected CO2 adsorbs into the coal seams, the process known as enhanced coalbed methane (ECBM) recovery. However, a significant concern lies in the loss of injectivity due to reduction in permeability by coal matrix swelling with CO2 adsorption although this effect can be partially be offset with ‘huff and puff’ scheme of cyclic CO2 injection followed by extraction of the released methane.The paper discusses the results of a numerical simulation study carried out with GEM compositional reservoir simulator to evaluate the effects of uncertainties in various reservoir parameters on the overall volume of CO2 storage and additional methane recovery before planning a pilot project in the Raniganj coalfield. A 3-m thick seam at 600 m depth was considered for fluid flow simulation study. While some information on the reservoir setting was obtained through literature and personal communication with the CBM operators, the rest of the information was derived through laboratory studies. The reservoir parameters considered for the study are injection pressure, adsorption capacity, permeability, cleat porosity, sorption time, and initial gas saturation. A 160-acre drainage area with 5-spot vertical well pattern was considered with one central injector and four producers on four corners of the study area.The maximum allowable injection pressure was estimated to be ∼ 850 psi (5856kPa) at the reservoir setting. The injection pressure was varied from 300 psi (2067kPa) to 850 psi (5856kPa) in the simulation and 600 psi (4134kPa) was found to be the optimum injection pressure. A number of adsorption isotherms on coals of Raniganj coalfield were established in the laboratory. The variations in the adsorption parameters observed through the isotherms were considered as uncertainty in the storage capacities. Significant variations were observed due to the variation in adsorption isotherms both for CO2 storage and additional methane recovery. Fracture permeability was varied from 3 md to 40 md, which is the range of permeability observed in the coalfield. The results of simulation indicate a strong influence of permeability on the CO2 storage and ECBM recovery. In the absence of specific information on sorption time, it was theoretically varied from a very fast-desorbing coal (sorption time of 1 day) to an extremely slow-desorbing coal (sorption time 200 days). Since rate of desorption from the coal matrix and fracture permeability are rate-control parameters, for each sorption time a low and a high permeability situation were considered. Fluid flow simulation study shows that variation in sorption time has no significant effect for a low permeability situation while some marginal effect in high permeability situation. Cleat porosity was varied from 0.5% to 1.5%. Within this range of porosities, enhanced methane recovery varied from 70% to 85% relative to the primary recovery but the volume of stored CO2 did not vary significantly. Lastly, the initial gas saturation was varied from 70% to almost 100% and both the CO2 sequestered volume and additional methane recovery were found to increase substantially.

Determination of the fracture pressure from CO2 injection time-series datasets

Successful operation of CO2 storage projects requires careful management of injection pressure to ensure that the integrity of the cap rock and other containment units is not compromised by mechanical failure. Injection of CO2 will lead to some increase in the pore pressure of the target storage formation and the project design will include some expected range of acceptable pressure variations required to achieve sufficient injectivity and to avoid loss of formation integrity. Accurate determination of the formation fracture pressures is a key factor controlling the maximum allowable injection pressure during operations. In this study we review the three main approaches for determining fracture pressure: (a) theoretical methods, (b) use of formation well-test data and (c) analysis of injection data during injection. While theoretical methods are valuable for early planning of projects, predictions based on formation well-test data are generally used immediately prior to and during injection operations. Using example site data, we show how careful analysis of wellhead pressure and rate data during injection operations may be used to optimize the injection plan using the actual in situ conditions in the rock formation around the injection well and for the specific properties of the injection fluid. Using injection pressure time-series datasets over an extended period of time allows improved accuracy in the estimation of the fracture pressure limits and an appreciation of their variation over a larger volume of the formation than can be estimated from well tests.

Gas-Injection Rate Needed for SAG Foam Processes To Overcome Gravity Override

Summary Gravity override is a severe problem in gas-injection enhanced-oil-recovery (EOR) processes, especially in relatively homogeneous formations. Foam can reduce gravity override. Shan and Rossen (2004) show that the best foam process for overcoming gravity override is one of injecting a large slug of surfactant followed by a large slug of gas, injected at constant, maximum-allowable injection pressure. This process works because foam collapses near the injection well, giving good injectivity simultaneously with mobility control at the leading edge of the gas bank. The supply of gas that would be needed to maintain constant injection pressure is a concern for EOR processes in which gas is produced industrially or from a separations plant with limited capacity: The available gas stream may not be sufficient for the optimal process. We show that for such a process, the pressure drop across the foam bank back to the injection well, at fixed injection rate, is nearly constant as the foam bank propagates radially outward. From this result, one can derive a simple formula to predict the rate of gas injection required for each of two limiting cases: An extremely strong foam at the foam front, many times more viscous than the fluids it displaces. In this case, the rate of gas injection required to maintain constant injection pressure is nearly constant, but injection rate is low. A foam just strong enough to maintain mobility control at its leading edge. In this case, injection rate required to maintain constant injection pressure increases steeply with time. Use of the formulae provides a quick initial estimate of how gas-injection rate must vary over the duration of the EOR process to maintain an optimal process. The fit to simulations of surfactant-alternating-gas (SAG) foam-injection rate in a five-spot pattern is remarkably good, especially for strong foam, given the simplicity of the model. In addition, we illustrate how one would determine the properties of a foam that would fit the available gas stream. This criterion then could guide the development of a surfactant formulation with these properties.

Coupled hydro-mechanical fault reactivation analysis incorporating evidence theory for uncertainty quantification

The injection of water (or CO2) at high pressure is a common practice to enhance oil production. A crucial component of this activity is the estimation of the maximum pressure at which the fluids can be injected without inducing the reactivation of pre-existing faults that may exist in the formation. The damage zones typically formed around the geological faults are highly heterogeneous. The materials involved in the damage zones are characterized by the huge variation of their properties and high uncertainties associated with them. To estimate the maximum allowable injection pressure this paper presents a novel approach based on: a coupled hydro-mechanical formulation (for the numerical analyses); a criterion based on the total plastic work (for the fault reactivation); and the evidence theory (for uncertainty quantification). A case study based on information gathered from an actual field is presented to illustrate the capabilities of the proposed framework.

Analysis of Reservoir Choke and Broken Down of Tong Liao Uranium Production

This project aims at the phenomenon of increasing injection pressure of injection wells of the Tong Liao Uranium SW-8E test wells group, carries out the research of reservoir choke and broken down. By analysis of the water quality of injected and produced fluid through the test wells, scaling prediction, physical simulation experiments and other research, we find the main cause of clogging injection wells: Bacteria blockage, scale blockage, solids blockage and reservoir clay swelling blockage. Meanwhile according to the main reasons of reservoir pollution we have carried on pointed research of broken down, excogitate a better integrated and targeted reservoir choke Blocking Remover. Through on-site implementation, the injection pressure is reduced by 0.3-0.4MPa (maximum allowable injection pressure is 2.0MPa), well purge period is extended from three days to three months, this project solves the problems and achieves very good results.

A study on pressure evolution in a channel system during CO2 injection

Risk assessment and feasibility studies based on numerical simulations are essential for a realisation of large scale carbon capture and storage projects. The numerical simulation of CO2 storage in deep saline aquifers, which is focused on in this study, is very demanding with respect to computational costs. During CO2 injection it is important to observe the pressure increase since it might result in caprock failure, reduction of storage capacity or brine displacement. For many reservoir parameters like e.g. the permeability only few information exists. More over the geological structure of the reservoir, e.g. the size and distribution of high permeable sand channels is often not known in detail. To deal with the resulting uncertainties the integrative probabilistic collocation method is applied to a channel system scenario. The influence of the dimension of the high permeable channel and the permeability on the pressure evolution is investigated in detail. Additionally, the maximum allowable injection rate is predicted with the method. Keywords CO2 storage · Pressure increase · Risk assessment · Probabilistic collocation method 1. Motivation

Optimal Injection Strategies for Foam IOR

SummaryMiscible-gas foam field trials have employed a variety of injection strategies, with mixed results. Using simulation, we compare foam-injection strategies in homogeneous reservoirs with a variety of foam models. The optimal injection strategy for overcoming gravity override with foam in a homogeneous reservoir is alternating injection of separate, large slugs of gas and liquid at fixed, maximum-allowable injection pressure. This strategy minimizes both gravity override and time of injection, with minimal rise in injection-well pressure. Injection of gas at maximum pressure can partially reverse the effects of gravity slumping of surfactant during injection of liquid. The process is remarkably insensitive to the detailed properties of the foam, as long as foam does not collapse abruptly and completely at a "limiting water saturation" Sw*. However, care is needed to exclude the effects of numerical artifacts in simulating such a process, especially if foam collapses abruptly and completely at Sw*.An idealized model for the process reveals the mechanisms responsible for process success, why injection at fixed injection pressure is better than injection at fixed rate, why details of foam behavior play a secondary role in sweep efficiency, and why numerical artifacts can be difficult to identify.

Assessment of injection volume limits when using on-column focusing with microbore liquid chromatography

It had been ascertained that in the use of microbore liquid chromatography (LC) and on-column focusing (peak compression), there were advantages to be had in using the strongest eluting injection solvent that would still bring about on-column focusing. In such cases, it was found that the scope for the use of on-column focusing with microbore LC was greater than previously imagined. It has been possible to explain these results by considering on-column focusing to take place in two distinct phases, i.e. focusing of the sample band due to the injection solvent, followed by further focusing of the sample band by the sample solvent/mobile phase step gradient. In this content, an equation has been developed which provides a much more accurate estimate of the maximum allowable injection volume for a given injection solvent and mobile phase than has been possible until now.

Estimation of the maximum allowable injection pressure for industrial waste disposal wells in Northeast Oklahoma : Bull Assoc Engng Geol V26, N3, Aug 1989, P343–350

Estimation of the maximum allowable injection pressure for industrial waste disposal wells in Northeast Oklahoma : Bull Assoc Engng Geol V26, N3, Aug 1989, P343–350

Evaluation of the Maximum Allowable Injection Pressure for Industrial Waste Disposal Wells in Northeast Oklahoma

Limitations on the pressure of injected fluids are necessary to preclude the initiation or extension of fractures. For formations within 2,000 ft (600 m) of the surface, the least principal stress which is exceeded during fracturing is often the overburden pressure. Density logs from 17 wells in the study area were integrated to evaluate the overburden pressure gradient of the Arbuckle Formation in northeastern Oklahoma. The regional gradient of 1.08 to 1.14 psi/ft (24.4 to 25.8 kPa/m) depth appears reasonable when compared with published data for the overlying Pennsylvanian sands. Under Oklahoma Rule 818, the maximum total pressure gradient for Class I industrial waste disposal wells shall not exceed sixty-five percent of the established overburden pressure gradient. In accordance with this Rule, injection pressure gradients less than 0.70 to 0.74 psi/ft (15.9 to 16.8 kPa/m) are permissible in the Arbuckle Group of Northeast Oklahoma. Information obtained while fracturing and acidizing the formation to improve injectivity, confirms the absence of fracturing at the allowable injection pressure gradients.