WASTE INJECTION: TESTING FOR MECHANICAL INTEGRITY1

ABSTRACT: Results of computer calculations are presented which predict the pressure response of a closed casing annulus of an injection well to temperature and pressure variations of the injected waste stream. For example, a 3000 ft. disposal well receiving fluid at 100d̀F might cause an increase in annular pressure of some 500 psi. Graphs summarizing these results are included. The results will be of interest to waste injection well operators, inasmuch as they are required to monitor annulus pressure to prove mechanical integrity of their injection wells.     

Screening and selection of sites for CO2 sequestration based on pressure buildup

This paper presents a simple methodology for estimating pressure pressure buildup due to the injection of supercritical CO₂into a saline formation, and the limiting pressure at which the formation starts to fracture. Pressure buildup is calculated using the approximate solution of Mathias et al. [Mathias, S.A., Hardisty, P.E., Trudell, M.R., Zimmerman, R.W., 2009. Approximate solutions for pressure buildup during CO₂ injection in brine aquifers. Transp. Porous Media. doi:10.1007/s11242-008-9316-7], which accounts for two-phase Forchheimer flow (of supercritical CO₂ and brine) in a compressible porous medium. Compressibility of the rock formation and both fluid phases are also accounted for. Injection pressure is assumed to be limited by the pressure required to fracture the rock formation. Fracture development is assumed to occur when pore pressures exceed the minimum principal stress, which in turn is related to the Poisson’s ratio of the rock formation. Detailed guidance is also offered concerning the estimation of viscosity, density and compressibility for the brine and CO₂. Example calculations are presented in the context of data from the Plains CO₂ Reduction (PCOR) Partnership. Such a methodology will be useful for screening analysis of potential CO₂ injection sites to identify which are worthy of further investigation.     

Coupled hydromechanical modeling of CO2 sequestration in deep saline aquifers

Sequestration of carbon dioxide (CO₂) in deep saline aquifers has emerged as an option for reducing greenhouse gas emissions to the atmosphere. The large amounts of supercritical CO₂ that need to be injected into deep saline aquifers may cause large fluid pressure increases. The resulting overpressure may promote reactivation of sealed fractures or the creation of new ones in the caprock seal. This could lead to escape routes for CO₂. In order to assess the probability of such an event, we model an axisymmetric horizontal aquifer–caprock system, including hydromechanical coupling. We study the failure mechanisms, using a viscoplastic approach. Simulations illustrate that, depending on boundary conditions, the least favorable moment takes place at the beginning of injection. Initially, fluid pressure rises sharply because of a reduction in permeability due to desaturation. Once CO₂ fills the pores in the vicinity of the injection well and a capillary fringe is fully developed, the less viscous CO₂ displaces the brine and the capillary fringe laterally. The overpressure caused by the permeability reduction within the capillary fringe due to desaturation decreases with distance from the injection well. This results in a drop in fluid pressure buildup with time, which leads to a safer situation. Nevertheless, in the presence of low-permeability boundaries, fluid pressure continues to rise in the whole aquifer. This occurs when the radius of influence of the injection reaches the outer boundary. Thus, caprock integrity might be compromised in the long term.     

高压注水井措施返排液回注技术探讨

在注水井进行措施作业前,存在放喷泄压时间长、返排液量大的难题,严重影响了措施作业的进度,也给油田生产带来很大的环保压力。利用井口自身注水工艺流程,将泄压放空的返排液经过处理后回注入注水井或者注水流程,对于油田生产和环境保护具有一定的重要意义。     

A method for quick assessment of CO2 storage capacity in closed and semi-closed saline formations

Saline aquifers of high permeability bounded by overlying/underlying seals may be surrounded laterally by low-permeability zones, possibly caused by natural heterogeneity and/or faulting. Carbon dioxide (CO₂) injection into and storage in such “closed” systems with impervious seals, or “semi-closed” systems with non-ideal (low permeability) seals, is different from that in “open” systems, from which the displaced brine can easily escape laterally. In closed or semi-closed systems, the pressure buildup caused by continuous industrial-scale CO₂ injection may have a limiting effect on CO₂ storage capacity, because geomechanical damage caused by overpressure needs to be avoided. In this research, a simple analytical method was developed for the quick assessment of the CO₂ storage capacity in such closed and semi-closed systems. This quick-assessment method is based on the fact that native brine (of an equivalent volume) displaced by the cumulative injected CO₂ occupies additional pore volume within the storage formation and the seals, provided by pore and brine compressibility in response to pressure buildup. With non-ideal seals, brine may also leak through the seals into overlying/underlying formations. The quick-assessment method calculates these brine displacement contributions in response to an estimated average pressure buildup in the storage reservoir. The CO₂ storage capacity and the transient domain-averaged pressure buildup estimated through the quick-assessment method were compared with the “true” values obtained using detailed numerical simulations of CO₂ and brine transport in a two-dimensional radial system. The good agreement indicates that the proposed method can produce reasonable approximations for storage–formation–seal systems of various geometric and hydrogeological properties.     

Dual poroelastic response of a coal seam to CO2 injection

Although the influence of gas sorption-induced coal deformation on porosity and permeability has been widely recognized, prior studies are all under conditions of no change in overburden stress and effective stress-absent where effective stresses scale inversely with applied pore pressures. Here we extend formalism to couple the transport and sorption of a compressible fluid within a dual-porosity medium where the effects of deformation are rigorously accommodated. This relaxes the prior assumption that total stresses remain constant and allows exploration of the full range of mechanical boundary conditions from invariant stress to restrained displacement. Evolution laws for permeability and related porosity are defined at the micro-scale and applied to both matrix and an assumed orthogonal, regular and continuous fracture system. Permeability and porosity respond to changes in effective stress where sorption-induced strains may build total stresses and elevate effective stresses. Gas accumulation occurs in both free- and adsorbed-phases and due to effective grain and skeletal compressibilities. A finite element model is applied to quantify the net change in permeability, the gas flow, and the resultant deformation in a prototypical coal seam under in situ stresses. Results illustrate how the CO₂ injectivity is controlled both by the competition between the effective stress and the gas transport induced volume change within the matrix system and by the dynamic interaction between the matrix system and the fracture system. For typical parameters, initial injection-related increases in permeability due to reduced effective stresses may endure for days to years but are ultimately countered by long-term reductions in permeability which may decline by an order of magnitude. Models suggest the crucial role of stresses and the dynamic interaction between matrix and fractures in correctly conditioning the observed response.     

Large-scale impact of CO2 storage in deep saline aquifers: A sensitivity study on pressure response in stratified systems

Large volumes of CO₂ captured from carbon emitters (such as coal-fired power plants) may be stored in deep saline aquifers as a means of mitigating climate change. Storing these additional fluids may cause pressure changes and displacement of native brines, affecting subsurface volumes that can be significantly larger than the CO₂ plume itself. This study aimed at determining the three-dimensional region of influence during/after injection of CO₂ and evaluating the possible implications for shallow groundwater resources, with particular focus on the effects of interlayer communication through low-permeability seals. To address these issues quantitatively, we conducted numerical simulations that provide a basic understanding of the large-scale flow and pressure conditions in response to industrial-scale CO₂ injection into a laterally open saline aquifer. The model domain included an idealized multilayered groundwater system, with a sequence of aquifers and aquitards (sealing units) extending from the deep saline storage formation to the uppermost freshwater aquifer. Both the local CO₂-brine flow around the single injection site and the single-phase water flow (with salinity changes) in the region away from the CO₂ plume were simulated. Our simulation results indicate considerable pressure buildup in the storage formation more than 100 km away from the injection zone, whereas the lateral distance migration of brine is rather small. In the vertical direction, the pressure perturbation from CO₂ storage may reach shallow groundwater resources only if the deep storage formation communicates with the shallow aquifers through sealing units of relatively high permeabilities (higher than 10^?18 m²). Vertical brine migration through a sequence of layers into shallow groundwater bodies is extremely unlikely. Overall, large-scale pressure changes appear to be of more concern to groundwater resources than changes in water quality caused by the migration of displaced saline water.     

INTERFERENCE BETWEEN GRAVITY WELLS STEADY STATE FLOW1

Under steady state conditions of flow, the seepage toward a single gravity well is governed by the Laplace Equation which may be written in terms of either the hydraulic head, the pressure head or the velocity potential. Although this equation is linear, the principle of superposition cannot be applied to sum up the individual effects in the case of a multiple gravity well system due to the variation of the flow domain under the effect of one or several wells. A method is presented allowing the use of the superposition principle in a restricted form. The superposition of the decrements of the base pressure heads than the initial heads before pumping is valid. Also the decrements in the areas of the pressure head diagrams across specific vertical sections than the original areas can be summed up together.     

挥发性油藏回注气井控因素分析及措施

文章明确了挥发性油藏天然气回注井控的安全环保关键因素;量化了低渗挥发性油藏天然气回注注入能力,确定注入端各节点安全生产压力分布,攻关相关配套工艺设备,实现安全有效注入;开展室内实验和PVT相态拟合,分析注天然气后天然气和原油性质变化规律,创新非混相驱组分数值模拟参数优化方法,开展带人工压裂裂缝的组分数值模拟,精准确定压力场分布,降低计量及监测不准带来的安全隐患;明确注气井气窜影响因素,优化注采参数,抑制油井气窜,降低生产风险,实现井控安全情况下的天然气驱环保高效开发。     

Pipeline design for a least-cost router application for CO2 transport in the CO2 sequestration cycle

CO₂ capture and geological storage (CCS) is considered as a viable option to mitigate greenhouse gas emissions during the transition phase towards the use of clean and renewable energy. This paper concentrates on the transport of CO₂ between source (CO₂ capture at plants) and sink (geological storage reservoirs). In the cost estimation of CO₂ transport, the pipeline diameter plays an important role. In this respect, the paper reviews equations that were used in several reports on CO₂ pipeline transport. As some parameters are not taken into account in these equations, alternative formulas are proposed which calculate the proper inner diameter size based on flow rate, pressure drop per unit length, CO₂ density, CO₂ viscosity, pipeline material roughness and topographic height differences (the Darcy–Weisbach solution) and, in addition, on the amount and type of bends (the Manning solution). Comparison between calculated diameters using the reviewed and the proposed equations demonstrate the important influence of elevation difference (which is not considered in the reviewed equations) and pipeline material roughness-related factor on the calculated diameter. Concerning the latter, it is suggested that a Darcy–Weisbach roughness height of 0.045 mm better corresponds to a Manning factor of 0.009 than higher Manning values previously proposed in literature. Comparison with the actual diameter of the Weyburn pipeline confirms the accuracy of the proposed equations. Comparison with other existing CO₂ pipelines (without pressure information) indicate that the pipelines are designed for lower pressure gradients than 25 Pa/m or for (future) higher flow rates. The proposed Manning equation is implemented in an economic least-cost route planner in order to obtain the best economic solution for pipeline trajectory and corresponding diameter.     

Basin-scale hydrogeologic impacts of CO2 storage: Capacity and regulatory implications

Industrial-scale injection of CO₂ into saline formations in sedimentary basins will cause large-scale fluid pressurization and migration of native brines, which may affect valuable groundwater resources overlying the deep sequestration aquifers. In this paper, we discuss how such basin-scale hydrogeologic impacts (1) may reduce current storage capacity estimates, and (2) can affect regulation of CO₂ storage projects. Our assessment arises from a hypothetical future carbon sequestration scenario in the Illinois Basin, which involves twenty individual CO₂ storage projects (sites) in a core injection area most suitable for long-term storage. Each project is assumed to inject five million tonnes of CO₂ per year for 50 years. A regional-scale three-dimensional simulation model was developed for the Illinois Basin that captures both the local-scale CO₂–brine flow processes and the large-scale groundwater flow patterns in response to CO₂ storage. The far-field pressure buildup predicted for this selected sequestration scenario support recent studies in that environmental concerns related to near- and far-field pressure buildup may be a limiting factor on CO₂ storage capacity. In other words, estimates of storage capacity, if solely based on the effective pore volume available for safe trapping of CO₂, may have to be revised based on assessments of pressure perturbations and their potential impacts on caprock integrity and groundwater resources. Our results suggest that (1) the area that needs to be characterized in a permitting process may comprise a very large region within the basin if reservoir pressurization is considered, and (2) permits cannot be granted on a single-site basis alone because the near- and far-field hydrogeologic response may be affected by interference between individual storage sites. We also discuss some of the challenges in making reliable predictions of large-scale hydrogeologic impacts related to CO₂ sequestration projects.     

Evaluation of large-scale CO2 storage on fresh-water sections of aquifers: An example from the Texas Gulf Coast Basin

Large-scale injections of CO₂ into subsurface saline aquifers have been proposed to remediate climate change related to buildup of green house gases in the atmosphere. The pressure buildup caused by such injections may impact a volume of the basin significantly larger than the CO₂ plume itself. In areas with hydrological settings similar to the Gulf Coast Basin, the perturbation of the flow-field in deep parts of the basin could result in brines or brackish water being pushed up-dip into unconfined sections of the same formations or into the capture zone of fresh-water wells. The premise of the current study is that the details of multiple-phase flow processes necessary to model the near field evolution of the CO₂ plume are not necessary to describe the impact of the pressure anomaly on up-dip aquifers. This paper quantitatively explores conditions under which shallow groundwater would be impacted by up-dip displacement of brines, utilizing an existing carefully calibrated flow model. Modeling an injection of water, arguably equivalent to 50 million tons of CO₂/year for 50 years resulted in an average water-table rise of 1 m, with minor increase in stream baseflow and larger increase in ground water evapotranspiration, but no significant change in salinity.     

Numerical investigation concerning the impact of CO2 geologic storage on regional groundwater flow

Large-scale storage of carbon dioxide in saline aquifers may cause considerable pressure perturbation and brine migration in deep rock formations, which may have a significant influence on the regional groundwater system. With the help of parallel computing techniques, we conducted a comprehensive, large-scale numerical simulation of CO₂ geologic storage that predicts not only CO₂ migration, but also its impact on regional groundwater flow. As a case study, a hypothetical industrial-scale CO₂ injection in Tokyo Bay, which is surrounded by the most heavily industrialized area in Japan, was considered, and the impact of CO₂ injection on near-surface aquifers was investigated, assuming relatively high seal-layer permeability (higher than 10 microdarcy). A regional hydrogeological model with an area of about 60 km × 70 km around Tokyo Bay was discretized into about 10 million gridblocks. To solve the high-resolution model efficiently, we used a parallelized multiphase flow simulator TOUGH2-MP/ECO2N on a world-class high performance supercomputer in Japan, the Earth Simulator. In this simulation, CO₂ was injected into a storage aquifer at about 1 km depth under Tokyo Bay from 10 wells, at a total rate of 10 million tons/year for 100 years. Through the model, we can examine regional groundwater pressure buildup and groundwater migration to the land surface. The results suggest that even if containment of CO₂ plume is ensured, pressure buildup on the order of a few bars can occur in the shallow confined aquifers over extensive regions, including urban inlands.     

Non-isothermal flow of carbon dioxide in injection wells during geological storage

During sequestration, carbon dioxide within injection wells is likely to be in a dense state and therefore its weight within the wellbore will play an important role in determining the bottomhole pressure and thus the injection rate. However, the density could vary significantly along the well in response to the variation in pressure and temperature. A numerical procedure is formulated in this paper to evaluate the flow of carbon dioxide and its mixtures in non-isothermal wells. This procedure solves the coupled heat, mass and momentum equations with the various fluid and thermodynamic properties, including the saturation pressure, of the gas mixture calculated using a real gas equation of state. This treatment is particularly useful when dealing with gas mixtures where experimental data on mixture properties are not available and these must be predicted. To test the developed procedure two wellbore flow problems from the literature, involving geothermal gradients and wellbore phase transitions are considered; production of 97% carbon dioxide and injection of superheated steam. While these are not typical carbon dioxide injection problems they provide field observations of wellbore flow processes which encompass the mechanisms of interest for carbon dioxide injection, such as phase transition, temperature and density variations with depth. These two examples show that the developed procedure can offer accurate predictions. In a third application the role of wellbore hydraulics during a hypothetical carbon dioxide injection application is considered. The results obtained illustrate the potential complexity of carbon dioxide wellbore hydraulics for sequestration applications and the significant role it can play in determining the well bottomhole pressure and thus injection rate.     

Variations of permeability and pore size distribution of porous media with pressure

Porosity and permeability of porous and fractured geological media decrease with the exploitation of formation fluids such as petroleum, natural gas, or ground water. This may result in ground subsidence and a decrease of recovery of petroleum, natural gas, or ground water. Therefore, an evaluation of the behavior of permeability and porosity under formation fluid pressure changes is important to petroleum and ground water industries. This study for the first time establishes a method, which allows for the measurement of permeability, porosity, and pore size distribution of cores simultaneously. From the observation of the pore size distribution by low-field nuclear magnetic resonance (NMR) relaxation time spectrometry the mechanisms of pressure-dependent porosity and permeability change can be derived. This information cannot be obtained by traditional methods. As the large-size pores or fractures contribute significantly to the permeability, their change consequently leads to a large permeability change. The contribution of fractures to permeability is even larger than that of pores. Thus, the permeability of the cores with fractures decreased more than that of cores without fractures during formation pressure decrease. Furthermore, it did not recover during formation pressure increase. It can be concluded that in fractures, mainly plastic deformation takes place, while matrix pores mainly show elastic deformation. Therefore, it is very important to keep an appropriate formation fluid pressure during the exploitation of ground water and petroleum in a fractured formation.     

Effects of tectonic stress environment on tectonophysical features of deformed coal

To study the effects of the tectonic stress environment on the tectonophysical features of deformed coal, No.8 Mine in the Pingdingshan mine area is used as a study area and the relationship between the development of deformed coal, distribution of fractures, formation of deformed coal and tectonic stress environment are analyzed. The results indicate that the thickness of the bedrock layer should be included in the analysis of the tectonic stress environment for a region of intense tectonic activity. Although the reverse faulting stress regime can control the development of deformed coal, the C seam is extremely sensitive to the stress regime. The most advantageous direction of the deformed coal fractures is consistent with the regional maximum principal stress, and the development of fractures is closely related to the evolution of the tectonic stress environment. The fracture density of the E seam presents a uniform distribution, yet that of the C seam is completely heterogeneous. Superposition and compounding of the tectonic communities evidently increase the fracture density of the deformed coal. There is a relatively apparent boundary between the different types of deformation, which gradually transform from brittle to ductile with a decreasing lateral pressure coefficient. A generalized deformation pattern of the deformed coal is proposed and can be divided into frictional sliding and solid flow.     

油田化工污水中总氰化物的检测

采用在线蒸馏-流动注射分析法检测大庆油田化工污水中总氰化物。分析流速和温度对流动注射仪检测结果的影响,得出结论:载流流速为1.8mL/min,显色剂流速在1.3mL/min,缓冲溶液流速稳定在1.6mL/min时,分析精度最好;显色反应在60℃以下进行时,可以消除温度差异对检测结果的干扰。该方法适用于油田化工废水中总氰化物的检测。     

3D geomechanical modelling for CO2 geologic storage in the Dogger carbonates of the Paris Basin

CO₂ injection into a depleted hydrocarbon field or aquifer may give rise to a variety of coupled physical and chemical processes. During CO₂ injection, the increase in pore pressure can induce reservoir expansion. As a result the in situ stress field may change in and around the reservoir. The geomechanical behaviour induced by oil production followed by CO₂ injections into an oil field reservoir in the Paris Basin has been numerically modelled. This paper deals with an evaluation of the induced deformations and in situ stress changes, and their potential effects on faults, using a 3D geomechanical model. The geomechanical analysis of the reservoir–caprock system was carried out as a feasibility study using pressure information in a “one way” coupling, where pressures issued from reservoir simulations were integrated as input for a geomechanical model. The results show that under specific assumptions the mechanical effects of CO₂ injection do not affect the mechanical stability of the reservoir–caprock system. The ground vertical movement at the surface ranges from ?2 mm during oil production to +2.5 mm during CO₂ injection. Furthermore, the changes in in situ stresses predicted under specific assumptions by geomechanical modelling are not significant enough to jeopardize the mechanical stability of the reservoir and caprock. The stress changes issued from the 3D geomechanical modelling are also combined with a Mohr–Coulomb analysis to determine the fault slip tendency. By integrating the stress changes issued from the geomechanical modelling into the fault stability analysis, the critical pore pressure for fault reactivation is higher than calculated for the fault stability analysis considering constant horizontal stresses.     

HYDROGEOLOGY AND PATHS OF FLOW IN THE CARBONATE BEDROCK AQUIFER,NORTHWESTERN INDIANA1

ABSTRACT: The U.S. Geological Survey (USGS) is assessing the ground-water resources of the carbonate bedrock aquifers in Indiana and Ohio as part of their Regional Aquifer Systems Analysis program. Part of this assessment includes the determination of unknown aspects of the hydraulic characteristics, boundaries, and flow paths of the carbonate aquifer. To accomplish this, the USGS drilled three wells through the carbonate aquifer near the Kankakee River in northwestern Indiana. Geophysical logs were used to help determine depths and thicknesses for testing and to help describe geology at the three wells. Packer tests were used to determine direction of ground-water flow and to provide data for an analysis of the distribution of transmissivity in the carbonate aquifer. Transmissivity of the carbonates is associated with two physical characteristics of the rocks: fractures and interconnected porosity. Almost all of the transmissivity is derived from horizontal fracturing; however, only a few of the fractures present in the carbonate are transmissive. Some transmissivity is associated with a zone of fossiliferous, vuggy dolomite, which yields water from the rock matrix. Most of the transmissivity is associated with large fractures and solution crevices in the upper 30 feet of the bedrock; less transmissivity is associated with the deeper vuggy reef material, even where extensively fractured. Transmissivity of individual fractures and fossiliferous zones ranges from 300 to 27,000 feet squared per day. The aquifer bottom is defined by a lack of transmissive fractures and an increased shale content near the contact of the Silurian and Ordovician sections. Water-level data from the three wells indicate that flow is horizontal at well site 1 north of the Kankakee River, upward at well site 2 near the river, and downward at well site 3 south of the river. Most of the flow occurs in the upper part of the carbonate bedrock where fracturing and solution-enlarged crevices are most developed. Water levels indicate the the Kankakee River is a hydrologic boundary for the regional carbonate bedrock aquifer.     

RECLAIMED WASTE WATER FOR GROUNDWATER RECHARGE1

ABSTRACT. The Orange County Water District has conducted studies in waste water reclamation and groundwater recharge since 1965. The work has been done in three phases: (1) Study in both laboratory and pilot-scale units on the feasibility of reclaiming trickling filter effluent for injection through wells into confined aquifers; (2) long-term injection study to determine the fate of injected reclaimed water and to observe the performance of a multi-casing injection well; (3) testing alternative treatment methods in a 25,000 gpd pilot plant to solve the water quality problems which developed during the injection study. The reclaimed trickling filter effluent was found to be injectable and did not cause excessive well clogging. The multi-casing injection wells performed very satisfactorily. The reclaimed water would be acceptable for domestic use after travel through 500 feet of a confined aquifer in that bacteria, virus and toxic material were consistently absent. However, the odor and taste which persisted in the injected reclaimed water and the high concentration of dissolved inorganics are undesirable characteristics. Methods to eliminate the odor are being tested at the present time. A cooperative project with the Office of Saline Water is under way to develop a source of desalted seawater to blend with reclaimed waste water.