Open Wellbore Research Articles

Numerical simulation on the heat extraction from the porous medium-low temperature geothermal reservoirs by self-circulation wellbore and its enhanced methods

Benefiting from the closed wellbore space for heat-carrying fluid circulation, the wellbore self-circulation technology can effectively avoid the problems of wellbore scaling, corrosion, formation deficit, and reinjection capacity decline in the traditional geothermal mining technology. However, its applicability and how to enhance the heat extraction rate still need to be further clarified, especially in the medium-low temperature geothermal reservoirs. In this study, a comprehensive simulation model on the heat extraction from a porous medium-low temperature geothermal reservoir in Xining Basin, China by self-circulation wellbore was established to study the heat extraction capacity and influencing factors. Different methods to improve the heat extraction rate of self-circulation wellbore were investigated, compared and discussed. The results show that the heat extraction rate of the self-circulation wellbore is relatively low. Under reasonable cycling, wellbore and reservoir conditions, the heat extraction rate can reach 20–100 kW, and the heat extraction range is mainly within 50 m around the well. The injection temperature, geothermal water seepage, and formation lithology have significant effects on heat extraction rate. The horizontal well, intermittent self-circulation, open self-circulation, and cross-layer pumping and reinjection can all enhance the heat extraction capacity of the self-circulation wellbore but with different disadvantages. Comprehensively considering the low capital cost, slight scaling and corrosion risk and good heat extraction performance, the self-circulation of open wellbore is the best way to enhance the heat extraction rate in a medium-low temperature geothermal reservoir.

Development of blocking compositions with a bridging agent for oil well killing in conditions of abnormally low formation pressure and carbonate reservoir rocks

Production well killing before workover operations in late-stage oil and gas-condensate fields can be complicated by abnormally low formation pressure, carbonate type of reservoir rocks, and high gas-oil ratio. These complications lead to the intensive absorption of technological fluids by the formation and gas ingresses, which, in its turn, increases the time of killing wells and putting them on production, reduction of productivity, and additional costs. Therefore, it is crucial to develop a high-performance well-killing composition that would allow improving the efficiency of killing wells in complicated geological, physical, and technological conditions at the expense of reliable overlapping of the perforation interval (or open wellbore) to prevent gas intakes and gas outflow from the formation. To develop blocking compounds, a set of laboratory tests has been carried out, including physical and chemical (determination of density, viscosity, thermal stability, sedimentation stability, etc.) and research of blocking and filtration properties of compositions during simulation of a fractured reservoir. In the course of laboratory tests, the choice of fractional composition and polymer filler concentration was substantiated in the blocking emulsion and polymer compositions to increase the efficiency of their application under the complicated conditions of killing oil wells. As a result of laboratory research and field tests, the emulsion and polymer blocking compositions containing bridging agent (microcalcite) were developed, which increase the oil well killing efficiency by preventing the absorption of technological fluids in the formations and, as a result, preserving its productivity.

Investigation of the Process of Mud Filtrate Invasion from an Open Wellbore into a Fresh Water

Investigation of the Process of Mud Filtrate Invasion from an Open Wellbore into a Fresh Water

Characterizing flow in the first hundred-meter depth of a fractured aquifer using hybrid seismic methods, acoustic logging, and flow-log measurements

Understanding subsurface flow, especially in fractured rocks only housing water through a few preferential pathways, is still challenging. The point is mainly associated with the poor accessibility of the subsurface and the lack of accurate representations for both heterogeneity and spatial distribution of water bearing bodies. This notwithstanding, highly-resolved geophysical investigations bring new images of the subsurface. This is exemplified over a fractured limestone aquifer at the site scale (for example, that of the radius of influence of an extraction well). On an experimental site, situated in the Cher region (France), two boreholes have been drilled for field experiments. Full Waveform Acoustic Logging (FWAL) and seismic experiments were conducted. Hybrid seismic imaging, which consists in combining refraction and reflection seismic results, has been carried out. Based on a four-step procedure, the processing of refracted and reflected waves provided two sections. After assemblage, these sections produced in a first step an extended time reflectivity section starting from the surface and, in a second step, a section over depth after calibration with Vertical Seismic Profile (VSP) and acoustic data. However, even the Very High Resolution (VHR) seismic methods do not have a sufficient vertical resolution to describe accurately the geological formation. The acoustic sections were processed to separate the different wave fields, to extract the criss-cross events and to build a criss-cross index log. A log of fracturation index, based on both criss-cross index and P-wave velocity measurements, was computed to detect the presence of fractures. After calibration, and under the assumption that the slower the P-wave velocity, the higher the permeability – porosity, a 3D seismic block of reflection can inform on preferential areas where flow should occur. At the scale of an open wellbore, acoustic loggings that measure wave velocities over a short distance within the well also inform on open features crosscut by the well. Finally, flow log measurements confirm the occurrence of flowing horizons that were previously marked by both seismic and acoustic data. Seismic and acoustic data are therefore suited to image contrasted hydraulic properties over fractured subsurface systems usually poorly documented.

Probabilistic risk-based Area of Review (AoR) determination for a deep-saline carbon storage site

Regulatory oversight of a geologic carbon sequestration (GCS) project relies on iterative estimations, throughout the project lifetime, of the area where increased risks to underground sources of drinking water (USDWs) may occur due to injection of CO2. This area, referred to as Area of Review (AoR), is typically delineated by predicting the migration of fluid between the reservoir and the lowermost USDW via an open wellbore using predictions from physics-based reservoir simulators. The inherent uncertainty in input parameters used in reservoir modeling therefore affects the accuracy of determining the AoR for a project. Furthermore, the standard analytical approaches for calculating a critical pressure to delineate the risk area yield an infinite AoR for cases where the injection reservoir is overpressured relative to the USDW. A methodology is presented here to better characterize the risk to USDWs while accounting for the uncertainty in reservoir modeling, with an application to a permitted GCS project with an overpressured injection formation, FutureGen 2.0. The methodology is demonstrated using the National Risk Assessment Partnership’s open-source integrated assessment model (NRAP-Open-IAM) to develop a probabilistic estimate of impact risk to USDW quality. CO2 and pressure predictions from the reservoir modeling conducted using the STOMP-CO2 simulator for the FutureGen 2.0 site are used in a NRAP-Open-IAM model with reservoir, wellbore, and aquifer components to: (1) assess the extent of potential leakage into the USDW for the predicted reservoir pressure conditions; (2) evaluate the extent of potential impact using “no-net-degradation” thresholds; and (3) account for uncertainty in reservoir permeabilities.

Seismic Imaging of Convective Geothermal Flow Systems to Increase Well Productivity

A core feature of convective geothermal resource production is wellbore energy flow Q ~ ρC x T x V. E.g., for wellbore fluid of volume heat capacity ρC ~ 4.3MJ/m3∙oC, temperature T ~ 230oC, and volumetric flow V ~ 50L/s, wellbore heat energy production is Q~ 50MWth ~ 5MWe. Wellbore fluid flow V =2πr0φv0ℓ for open wellbore length ℓ is given in turn by the spatially variable product crustal porosity times crustal fluid velocity v ≡ φv0 at the wellbore radius r0. For a geothermal wellbore to be productive (nominal Q ~ 5MWe), locally variable bulk inflow rates v = φv0 across crustal volumes of dimension ℓ must be adequate to sustain high wellbore flows (nominal V ~ 50L/s). Wide-ranging crustal well productivity statistics show that few crustal wells flow at these rates. This is not surprising as local bulk flow ~ 10-2 m/s needed for production wellbores is decades greater than ambient bulk fluid flow ~ 10-8-10-7m/s characteristic of natural convective geothermal systems. Such rare high flow locales must be found. While existing crustal surveys generally fix resource temperatures T with nominal 500m spatial resolution, as yet no survey technique provides data to locate production-grade flow rates at nominal ℓ ~ 50m spatial resolution. In consequence, many costly unproductive wells are drilled before sites of productive local geothermal fluid bulk flow v = φv0 ~ 10-2 m/s are located. A seismic survey methodology sensitive to crustal flow v = φv0 at ℓ ~25m resolution has evolved from multi-channel seismic reflection technology applied to the production of shale hydrocarbons. The field-proven seismic flow-imaging methodology can be adapted from sedimentary terrains to volcanic terrains through appropriate seismic refraction means for generating effective seismic velocity models for convective geothermal flow volumes. Numerical simulation for characteristic ambient crustal heterogeneous flow distributions v = φv0 at ℓ ~50m resolution shows that travel-time data for seismic source energy refracted from deep geothermal wellbores to surface seismic sensor arrays can replicate the multi-channel seismic flow-imaging capability demonstrated for shale formations. Multi-channel seismic reservoir flow monitor detection and mapping of flow-induced seismic emissions in shale formations can be adapted to achieve similar mapping of convective geothermal flow system structures with v = φv0 ~ 10-2m/s at nominal ℓ ~ 50m resolution. Such seismic emission flow structure maps can greatly reduce the uncertainty and hence the cost of drilling effective production wells at brownfield sites and assessment/development wells at greenfield sites

Обзор и анализ применяемых бесклиновых технологий по забуриванию новых направлений из открытого ствола скважины в твердых и крепких горных породах

Обзор и анализ применяемых бесклиновых технологий по забуриванию новых направлений из открытого ствола скважины в твердых и крепких горных породах

Field‐scale well leakage risk assessment using reduced‐order models

AbstractOil wells that intersect a potential CO2 storage zone in a depleted oil and gas field may provide leakage pathways. It is essential to estimate the field‐scale leakage risk associated with these wells. In this study, a risk‐based approach is used to estimate the risk of leakage. Existing reduced‐order models for well leakage are used to quantitatively estimate well leakage rates for cased‐cemented, cased‐uncemented, and open wellbores. For each existing well that intersects the storage zone, we introduce the well leakage index (WLI), which accounts for wellbore geometry, distance from the injection well, buffer layers between the storage zone and underground sources of drinking water, and the nature of storage zone boundary type. For an initial injection well location, the total site well leakage index (SWLI) is calculated, which is the summation of the WLI for all of the wells. Next, the injector location is varied areally and SWLI is calculated for a specified number of potential injector well locations in the storage zone area. Small values for the SWLI correspond to low well leakage potential, indicating where injection well locations can be considered. The developed criterion provides a means to systemically find the areas with highest and lowest well leakage potential for a storage zone. Due to the reduced order nature of the developed method, it should be a useful tool in the planning and execution phase of the CO2 geological sequestration process. © 2019 Society of Chemical Industry and John Wiley & Sons, Ltd.

Обоснование безопасных режимов эксплуатации водозаборных скважин Ваделыпского месторождения

The sand production problem for the water sources wellbores at the Vadelypskoye oilfield that is located in Hanty-Mansy region of Russia is considered. The serious issue during field operations is the open wellbore wall destruction even if low drawdown rates (4-6 bar) are applied to the water-bearing pay at one kilometer depth. Petrophysical analysis of high permeable (0.6-2.5 D) sandstones of water-bearing pay is presented. The effectiveness of the sands prevention methods used at the deposit is discussed and the practical recommendations for drilling and operations are given. To identify the conditions of safe fluid extraction the three-dimensional poroelastic software was used for modeling of the vertical borehole section located in the water saturated sandstone. We consider the mudcake is stripped and disappeared due to the wellbore technological operations but the plugging zone persisted. The colmatage zone was taken into account in the modeling as the radial area with reduced relative to formation permeability. Along with this, the axial sandstone permeability is non-uniform and assigned according to the core data. Different horizontal stresses ratios and values are considered in the simulations. The medium-clogged and high‑clogged damage zone influence on the formation effective stresses was studied for minimal and maximal drawdown values. It was established that the most stable borehole relative to the draw-down is located in the homogeneous horizontal stress field within the medium-clogged damage zone. Special attention was given to the damage zone permeability and thickness influence on the wellbore wall failure while pumping. It was determined that rock failure is more possible when the thin and low-permeable colmatage zone is built in formation. The near-wellbore zone colmatage effect on rock destruction can be definitely seen for conditions of equal horizontal stresses but decreases when horizontal loads are unequal. The analysis of different in-situ conditions showed that the difference between horizontal stresses has more effect on destruction than colmatage zone parameters changes. The water-pumping admissible drawdown pressure ranges are specified for each horizontal stresses regime and the recommendations were given for sanding screen characteristics. For wellbore planning at the Vadelypskoye deposit the preferable drill mud composition was described that will contribute to subsequent safe water pumping.

Estimating Ultralow Permeability at Multiple Locations Using Simultaneous-Impulse Tests: A Fit-for-Purpose Pressure-Transient Solution and Its Field Application

Summary One of the major challenges in efficiently developing ultratight or shale reservoirs is to obtain reliable permeability distribution. Ultralow permeability and very strong stratification or heterogeneity in the formations require conducting long-duration tests at multiple locations in a well to attain a complete reservoir characterization. Because of these characteristics, existing tools or methods that work well for conventional reservoirs are usually not applicable for ultralow-permeability formations. An innovative reservoir-monitoring/testing tool system was developed and successfully applied to fields in both the United States and Canada (Zhan et al. 2016). The tool created multiple pressure pulses at targeted locations simultaneously along monitoring wells for zonal in-situ permeability estimations as well as long-term formation-pressure monitoring. Existing pressure-transient solutions are incapable of handling the measured data when potential zonal-pressure interferences appear. A fit-for-purpose pressure solution, the associated optimization algorithm, and a suitable data-interpretation work flow were developed to analyze the data whenever commercial software tools are inadequate. The new solution fully considers all impulses as well as potential interferences among them through suitable superposition. In-situ permeability values at all involved zones can be obtained through a combination of individual-impulse analyses and systematic multiple-impulse inversions. The new pressure-transient solution was verified through comprehensive synthetic cases using numerical simulations. The results show that the solution can handle either fully or partially open wellbores in each zone and properly considers crossflow between formation layers. In addition, it allows any number of perforated intervals and formation layers where the number of perforated intervals is fewer than that of the formation layers. Field examples demonstrate the applicability of the new solution and the data-interpretation work flow to formation permeability down to tens of nanodarcies. The detailed zonal-permeability distribution in the formation enables a more-representative reservoir model for better hydraulic-fracturing design and field-development optimization.

Mechanical model and optimal design method of tubular strings with connectors constrained in extended-reach and horizontal wells

Mechanical analysis and optimal design of down-hole tubular strings with connectors are the key theoretical bases of design and operation in extended-reach and horizontal drilling and completion. However, the complex mechanical interaction between spring connectors and open wellbores are not fully considered in conventional tubular models and the conventional design methods are mostly based on experience and lack of rigorous mathematical derivations. To overcome these shortcomings, a new revised mechanical model and an optimal design method of connectors on down-hole tubular strings have been built. Firstly, the local loads on a unified connector which can depict common spring and rigid connectors constrained in open wellbores are studied. The local connector loads are further introduced into the local mechanical model of tubular strings. The integral mechanical model of tubular strings is amended by the local model. Next, the integral design model of connectors while considering friction reduction, tubular centricity and cost is built. The integral design model is divided into a series of local design models according to the properties of tubular mechanical behaviors on extended-reach and horizontal wellbores. At last, the mechanical model and design method are applied to drill strings with joints and casing strings with centralizers in horizontal drilling and completion.The results indicate that the revised tubular mechanical model and connector design model are stable and fast. The coupling effects of connector and buckling, local drags on connector and radial compression of spring connectors are all included in the mechanical model, so the new model gives a more sophisticated description of mechanical behaviors of tubular strings with connectors. The design results of anti-drag joints are closely related to the clean condition of wellbores. Proper optimal design of connectors and good clean condition of wellbores can inhibit helical buckling, decrease friction factor and reduce plough effect, leading to larger lateral extending limits. Compared with the initial design results of centralizers, friction force is decreased and casing centricity is increased through optimization design. The optimization results of centralizers are closely related to the weight values of friction reduction, casing centricity and cost. Therefore, the key problem is how to assign these three weight values under actual engineering conditions.

Оптимизация и совершенствование технологии забуривания новых направлений в открытом стволе скважины с опорой на искусственный забой

Оптимизация и совершенствование технологии забуривания новых направлений в открытом стволе скважины с опорой на искусственный забой

Numerical studies of CO2 and brine leakage into a shallow aquifer through an open wellbore

Industrial-scale geological storage of CO2 in saline aquifers may cause CO2 and brine leakage from abandoned wells into shallow fresh aquifers. This leakage problem involves the flow dynamics in both the wellbore and the storage reservoir. T2Well/ECO2N, a coupled wellbore-reservoir flow simulator, was used to analyze CO2 and brine leakage under different conditions with a hypothetical simulation model in water-CO2-brine systems. Parametric studies on CO2 and brine leakage, including the salinity, excess pore pressure (EPP) and initially dissolved CO2 mass fraction, are conducted to understand the mechanism of CO2 migration. The results show that brine leakage rates increase proportionally with EPP and inversely with the salinity when EPP varies from 0.5 to 1.5 MPa; however, there is no CO2 leakage into the shallow freshwater aquifer if EPP is less than 0.5 MPa. The dissolved CO2 mass fraction shows an important influence on the CO2 plume, as part of the dissolved CO2 becomes a free phase. Scenario simulation shows that the gas lifting effect will significantly increase the brine leakage rate into the shallow freshwater aquifer under the scenario of 3.89% dissolved CO2 mass fraction. The equivalent porous media (EPM) approach used to model the wellbore flow has been evaluated and results show that the EPM approach could either under- or over-estimate brine leakage rates under most scenarios. The discrepancies become more significant if a free CO2 phase evolves. Therefore, a model that can correctly describe the complex flow dynamics in the wellbore is necessary for investigating the leakage problems.

Measuring water quality from individual fractures in open wellbores using hydraulic isolation and the dissolved oxygen alteration method

This study describes a low-cost method for sampling individual fractures in open wellbores in crystalline bedrock utilizing naturally occurring flow conditions in the well. The method entails using the dissolved oxygen alteration method (DOAM) to identify transmissive fractures and vertical flow direction. After obtaining information about relative hydraulic gradients, flow direction in the well is modified using a single control pump to isolate fractures of interest for sampling. Additional dissolved oxygen, injected during the DOAM procedure, serves as a tracer to ensure the water quality in the sampling zone is characteristic of the fracture of interest by requiring a tracer-free zone prior to sampling. Sampling procedures are described conceptually for nine bedrock wells with varying flow conditions containing one, two, or three transmissive inflowing fractures. The method was demonstrated in two crystalline bedrock wells containing one and two transmissive inflowing fractures.

The Effect of Leaky Well Permeability Distribution on Probabilistic Risk Maps in Geologic Carbon Storage

A probabilistic methodology to generate “risk maps” for determining the spatial extent and associated probability of groundwater leakage risk at Geologic Carbon Storage (GCS) sites was recently developed and is tested for well permeability distribution sensitivity here. Although the risk map methodology is general and may be used to assess leakage of either CO2 or brine, the degree to which risk may occur via plugged and abandoned (P&A) brine leakage is arguably the most uncertain. This uncertainty stems from the possibility of a high number of undocumented wells at a given injection site which, even when properly plugged, may yield a number of different leakage pathways. Furthermore, determining the spatial extent and probability of brine leakage through P&A wells is not straightforward. The aforementioned risk maps are probabilistic and are based on the premise that two of the greatest sources of uncertainty in brine leakage through P&A wells are the location of the unknown well with respect to the injection well and the permeability of the leaky well (which can span over several orders of magnitude). The methodology utilizes either analytical solutions or numerical simulations in conjunction with probability theory to generate spatial distributions of risk. Risk is defined with either no-impact levels (i.e. zero brine concentration above background in the drinking water aquifer) or other user defined thresholds such as the secondary maximum contaminant level (SMCL) for total dissolved solids, a non-health related standard related to water hardness, color, and taste. These probabilistic maps can be used to provide risk-based descriptions of the injection area to inform site selection prior to injection and monitoring during or after injection has ceased, similar to the United States Environmental Protection Agency's definition of the area of review (AoR). However, unlike the AoR definition, we differentiate risks according to a tiered approach, where CO2 leakage risk and brine leakage risk through P&A wells and open wellbores are assessed separately given that not only do the risks differ considerably, the spatial extents of each hazard do as well. A strength of this methodology is its demonstrated efficiency, which unlike computationally expensive Monte Carlo techniques that could require several thousands of simulations, requires only on the order of tens of simulations. Here, we assess the sensitivity of risk maps of a hypothetical, yet realistic GCS leakage scenario. In this sensitivity analysis, risk maps are generated with varying leaky well permeability distributions including differences in distribution modality and distribution variance. This work is motivated by the unknown quality to which many wells are sealed and/or the degree to which they degrade over time, in addition to the sheer unknown quantity of which P&A wells may be present at a single Geologic Carbon Storage site. Quantitative probabilities of exceeding contamination thresholds in the USDW are used for discussion, a practical metric for decision-makers and stakeholders. Results show that the modality of the leaky P&A distribution plays an important role in the risk profile and that larger variances in leaky P&A well permeability distribution may result in an overall lower profile of risk, depending on the upper-threshold of the distribution.

Factory-like Optimum Drilling Design of Cluster Well in Jimsar Well Block

The deep heavy oil reservoir of Jimsar well block, which located in Xinjiang oilfield, was developed by cluster well in 2016. In view of the ground environment, long open hole section and poor wellbore stability, the scheme which based on the research of factory-like wellsite platform deployment, well trajectory design and reservoir protection, was designed and carried out in the block. Firstly, the platform was divided into different control regions according to the anti-collision requirement. Secondly, truck-mounted drilling rig and civil power were applied to the factory-like drilling. Thirdly, well track was designed to be three parts: straight, increase and steady. The design can improve the proportion of composite drilling footage. Fourthly, the method of plane scanning and normal surface scanning was adopted to ensure the safety of downhole trajectory. Finally, the natural polymer drilling fluid system and drilling fluid reuse system were used to protect environment and reduce drilling cost. The results show that the maximum reducing time of single drill rig is 32.5 day, and the penetration rate of whole platform is increasing continuously.

Worn pipes collapse strength: Experimental and numerical study

Abstract After drilling an oil or gas well the open well-bore is usually cased with steel pipes, which must be properly designed to support all predicted loads (pressures) along its service life. Such casing can be subject to material loss after deployed. One of the reasons for material loss comes from that the well-bore is drilled deeper with rotating drill pipes after casing installation. The interaction between the rotating drill-pipes and casing inner wall leads to the casing wear, which can significantly reduce the wall thickness at particular regions. Casing designers usually assume evenly distributed inner casing wear. Under this assumption the remaining wall is constant and the predictive burst and collapse strength equations presented by standards are applied, but resulting in much lower strength values than the real case. Few authors studied the pipe remaining strength under more realistic wear assumptions. Kuryama et al. presented an analytical formulation based on pipes with circular cross-section and an equivalent wall thickness eccentricity to simulate material loss over an angular section. Sakakibara et al. presented a model for collapse strength prediction of worn pipes with initial geometric imperfection (cross-section ovalization) and constant pipe wall loss within a given angular section. None of them combined real initial (ovalization and eccentricity) and produced (casing wear) geometric imperfections. This paper presents the full scale experimental set up and results for thin and thick walled intact and worn pipes under applied external hydrostatic pressure. The test procedure included pipes’ geometry mapping and wear production to match real conditions. The specimens were collapsed and numerical analysis based on finite element analysis and an analytical model were carried out to simulate physical conditions. The numerical results were then extended to a broad range of pipes with different geometries and steel grades representative of drilling well applications. As expected, one developed model developed predicts really well thin walled pipes, but not for thicker ones.

Application of Multiphysics Coupling FEM on Open Wellbore Shrinkage and Casing Remaining Strength in an Incomplete Borehole in Deep Salt Formation

Drilling and completing wells in deep salt stratum are technically challenging and costing, as when serving in an incomplete borehole in deep salt formation, well casing runs a high risk of collapse. To quantitatively calculate casing remaining strength under this harsh condition, a three-dimensional mechanical model is developed; then a computational model coupled with interbed salt rock-defective cement-casing and HPHT (high pressure and high temperature) is established and analyzed using multiphysics coupling FEM (finite element method); furthermore, open wellbore shrinkage and casing remaining strength under varying differential conditions in deep salt formation are discussed. The result demonstrates that the most serious shrinkage occurs at the middle of salt rock, and the combination action of salt rock creep, cement defect, and HPHT substantially lessens casing remaining strength; meanwhile, cement defect level should be taken into consideration when designing casing strength in deep salt formation, and apart from the consideration of temperature on casing the effect of temperature on cement properties also cannot be ignored. This study not only provides a theoretical basis for revealing the failure mechanism of well casing in deep complicated salt formation, but also acts as a new perspective of novel engineering applications of the multiphysics coupling FEM.

Closure of open wellbores in creeping salt sheets

Safe exploration and production of pre-salt (or subsalt) hydrocarbons require that drilling operations be optimized. We introduce analytical models of wellbore closure, accounting for variations in both the wellbore net pressure and far-field flow rate of an autochthonous or allochthonous salt sheet penetrated by the wellbore. We demonstrate how closure rates of such a wellbore evolve for increasingly stronger Rankine flow. For high viscosity salt (?10^18 Pa s) the wellbore closes by a pure sink flow without any Rankine shift from its vertical trajectory path. For low viscosity salt (?10^16 Pa s) Rankine flow dominates.Wellbore closure in salt sheets may vary within the same wellbore due to differential tectonic creep rates at different depths. Mitigation of wellbore closure by, for example, reaming, jarring, brine solution and thermal control, is most effective if spatial variation in closure rates is understood and quantified. Evaluation of wellbore closure rates due to salt creep should be customarily included in wellbore stability analyses before drilling and during well monitoring.

Semi-analytical Solution for Brine Leakage Through Passive Abandoned Wells Taking Account of Brine Density Differences

Both $$\hbox {CO}_{2}$$ storage and disposal of waste fluid (e.g., co-produced brine) in deep saline aquifers of sedimentary basins create large scale over-pressurization and tend to displace brine upwards if a vertical connection (e.g., an abandoned well) is present. This raises groundwater pollution issues of brine intrusion into shallower potable water aquifers. When saline brine from the deep aquifer is displaced upwards it lifts and replaces the a priori less saline, less dense water initially filling the connection, resulting in a weight increase that counters leakage. This article presents and explains an innovative semi-analytical solution to this problem of leakage between two aquifers connected by a passive well (represented by a porous column and/or an open wellbore) taking account of the effect of the density difference between lifting and lifted brines during both upward and downward flow. It is based on the linearization of brine density profiles against depth and on two improvements made to the approximate evaluation of convolution products introduced in Nordbotten et al. (Water Resour Res 40:W04204, 2004) for calculation of the pressurization induced by transient flows in open aquifers. The comparison with numerical simulations shows good agreement of results. Since the solution uses time discretization but no spatial grid, computation time is reduced by 3–4 orders of magnitude compared to numerical resolution. It does, however, require considering homogeneous aquifers of constant thickness and brine properties.