Underground Gas Storage Reservoir Research Articles

In Situ Stress Evolution and Fault-Slip Tendency Assessment of an Underground Gas Storage Reservoir in the Turpan Basin (China): In Situ Stress Measurements and Coupled Simulations

In Situ Stress Evolution and Fault-Slip Tendency Assessment of an Underground Gas Storage Reservoir in the Turpan Basin (China): In Situ Stress Measurements and Coupled Simulations

Gas Injection Capacity of Slotted Liner and Perforation Completion in Underground Natural Gas Storage Reservoirs

The use of Horizontal wells is a common method of underground natural gas storage (UGS), but there is still a need to discuss whether they are more suitable for slotted liner or perforation completions. To address this issue, a numerical model is developed to predict the gas injection rate of horizontal wells while considering the skin factor. Here, a novel uncoupled iteration method is employed to determine the skin factor deriving from turbulence in each time step when the bottom hole pressure is fixed. The uncoupled method begins with an estimate of the initial gas injection rate, which is then used to calculate a turbulent skin factor. This turbulent skin factor is then used to update the gas injection rate, iterating continuously until convergence is achieved. The effects of slotted liner and perforation design parameters, formation damage, and injection pressure on the skin factor are analyzed. The main findings suggest that the error in the gas injection rate calculated by the non-coupled model compared with the coupled model is only 0.6%, yet it can reduce the number of sub-iterations to 1/10 of that required by the coupled model. Moreover, the uncoupled model can provide results within four steps, even when the convergence condition is 10−14. The open area and perforation density play a significant role in determining the connection degree between the horizontal well and the reservoir, with a larger perforation density resulting in a negative skin factor. Perforations are more suitable than slotted liners for reservoirs with severe formation damage, and the difference in skin factor between the two can reach a value of 40.87 when the ratio of the damage zone’s permeability to that of the normal reservoir zone is 0.05. It is easier to reduce turbulence damage in slotted liner completions than perforation completions, with the turbulence damage of the slotted liner being only 15.9% of that of the perforation. However, to avoid damage it is crucial to prevent the screen tube from being plugged in, as it might otherwise rise to three to ten times the original level. This study provides a theoretical basis and practical reference for the application of slotted liner and perforation method in UGS horizontal wells.

Application of the in-situ stress testing technology for the design of operating pressure of underground gas storage reservoir

The appropriate design of the operating pressure of underground gas storages (UGSs) is of great significance to their safe and profitable operation. In situ stress is basic data for determining the upper limit pressure of UGSs, analyzing fault stability in reservoir areas, and evaluating trap tightness. Generally, the design of the upper limit gas injection pressure of UGSs is a comprehensive geomechanical problem. After research and comparison of measurement methods, it is believed that the measurement of in situ stress induced by hydraulic fracturing can accurately obtain the in situ stress value near the wellbore, and having knowledge about the reservoir stress path will considerably decrease the risk of reservoir and cap rock instability during gas injection and production. Taking Well C1, an oil reservoir-type UGS in Block M, eastern China as an example, this paper introduces the use of hydraulic fracturing (HF) in situ stress testing technology to obtain the minimum principal stress values of the caprock, reservoir and floor intervals of Well C1. The measured minimum principal stress of the caprock is 32.8–36.8 MPa. Because it is an old well, the minimum principal stress of the reservoir is 33.7–34.2 MPa after correction of the in situ stress measurement according to the theory of elasticity. Based on the comprehensive analysis of the measured in situ stress data, it is believed that the safe upper limit of the reservoir-type gas storage in Block M is 27.2 MPa.

Discussion on the Reconstruction of Medium/Low-Permeability Gas Reservoirs Based on Seepage Characteristics

The construction of underground gas storage mostly focuses on depleted gas reservoirs. However, the depleted gas reservoir used to build underground gas storage in China is located far from the main gas consumption economic zone. It is necessary to reconstruct underground gas storage using nearby reservoirs in order to meet the needs of economic development. The complex three-phase seepage characteristics encountered in the process of reconstruction of underground gas storage reservoirs seriously affect their storage and injection production capacities. Combined with the mechanism of multiphase seepage and the multicycle injection production mode during the process of gas storage construction, the feasibility of rebuilding gas storage in medium- and low-permeability reservoirs was evaluated through relative permeability experiments and core injection production experiments. The results showed that the mutual driving of two-phase oil–water systems will affect the storage space and seepage capacity, that the adverse effect will be weakened after multiple cycles, and that increasing the gas injection cycle can enhance the gas-phase seepage capacity and improve the crude oil recovery. Therefore, we found that it is feasible to reconstruct underground gas storage in medium- and low-permeability reservoirs, which lays a foundation for the development of underground gas storage in China.

Probabilistic-based geomechanical assessment of maximum operating pressure for an underground gas storage reservoir, NW China

One of the most cost-effective ways to increase deliverability and working gas capacity in underground gas storage (UGS) reservoirs is to operate the gas storage at higher pressure (increased delta pressure). Maximum operating pressure (MOP) for a gas storage reservoir depends on several geomechanical factors, including in-situ stresses, stresses induced by local and global pressure changes in the storage reservoir, and the stabilities of the caprock and faults. PetroChina’s Hutubi (HTB) gas storage site is located in the west gate of China’s west–east gas pipeline project. Multiple major faults intersect the gas storage reservoir and caprock, which pose safety concerns for increasing the gas storage pressure. The typical practice in an HTB storage site has been to operate gas storage pressures at levels equal to the original reservoir pressure because of concerns related to caprock integrity and fault stability. To investigate the possibilities of increasing the gas storage pressure, a comprehensive geomechanical study has been conducted. By utilizing the data from rock mechanics laboratory testing, in-situ stress measurements, 3D field-specific geomechanical models, and coupled reservoir-geomechanical simulations, this paper presents probabilistic risk assessment of fault slippage in response to injection-related increases in pore pressure. Uncertainties of relevant geomechanical parameters, such as the frictional strengths of faults, orientation, and magnitudes of in-situ stresses, have been incorporated through Monte Carlo simulations. The authors find that: (1) fault slippage is the controlling factor which determines the limit of MOP at a HTB gas storage site; (2) increasing the gas storage pressure by 12.5% above the initial reservoir pressure (34.5 MPa) leads to approximately 0.6% probability of fault instability that could provide a leakage pathway. Thus, from a geomechanical perspective, operating the storage pressure at initial reservoir pressure at a HTB gas storage field is an overly conservative approach that leads to under-utilization of the existing storage capability. This paper provides the first integrative geomechanical study for increasing MOP for large underground gas storage reservoir in China. The methodology as well as comprehensive data repository are potential sources for future geomechanical studies on similar underground gas storage projects.

Numerical simulation and laboratory experiments of CO2 sequestration and being as cushion gas in underground natural gas storage reservoirs

Underground natural gas storage reservoir is generally used to stabilize the natural gas supply to meet the high and low peak of gas consumption. In addition, in the case of depleted gas reservoirs, the leftover native gas or cheap inert gas being as the cushion gas is needed to maintain reservoir pressure and ensure the stability of gas storage. In recent years, injecting CO2 for use as the cushion gas has drawn great attention for its potential to sequestrate the greenhouse gas underground and improve the operating efficiency of the working gas. In this study, a three-dimensional component model coupled with convection and diffusion is firstly constructed to describe the flow and miscible displacement processes affected by mixing in the porous media surrounding storage wells, and a fully implicit numerical model is established based on unstructured tri-prism meshes and a hybrid control volume finite element (CVFE) and finite-difference (FD) method. Secondly, mixing experiments of CO2 as cushion gas are carried out, the results are verified by numerical model, and good agreement between measured and computed data is achieved. Finally, through the numerical simulation of the hypothetical cases and orthogonal experiments, it is can be concluded that: CO2 is more suitable as cushion gas than natural gas itself and N2, injecting CO2 through corner wells at the bottom layer can effectively prevent the working gas escaping, and help to store more CO2 and slow down the mixing zone runs up, and the high production rate will help to control the mixing zone at a lower position and obtain greater gas recovery.

Prospects for Production and Use of Hydrogen as one of Directions of the Development of Low-Carbon Economy in the Russian Federation

Prospects for the production and use in the Russian Federation of hydrogen produced from fossil fuel and by water electrolysis are considered. The amount of hydrogen produced by steam conversion of hydrocarbons, required for the production of ammonia, methanol, petroleum products, and products of direct iron reduction, was estimated from the predicted levels of production of these substances in Russia. The feasibility of using the existing underground gas storage reservoirs for the disposal of carbon dioxide formed by steam conversion of hydrocarbons was substantiated. The possibility of large-scale hydrogen production by water electrolysis with more efficient utilization of the existing facilities at nuclear and hydroelectric power plants and of gas-cooled high-temperature reactors that are now under development was assessed. The creation of territorial hydrogen clusters with the required potential for the production, storage, and export of hydrogen to European and Asia–Pacific countries was suggested. The possibilities of using hydrogen and methane–hydrogen mixtures for reducing the carbon dioxide emissions in operation of automobile transport, mining of mineral resources, electric power production, and process industry were assessed.

An engineering approach to quantify geomechanical safety factors in UGS programs

Abstract. Underground Gas Storage (UGS) has become one of the most widely used practices to cope with seasonal peaks in energy consumption. The planning of any new UGS facility, or its upgrading to increase the working gas volume and reservoir performance, must be supported by an evaluation of possible induced effects on the environment. From a geomechanical point of view, storage activity results in a cyclic change in stress and deformation in the reservoir rock and the surrounding formations. The main environmental issues to be accounted for when natural fluid pore pressure is planned to be exceeded are the following: (a) the differential displacements at the land surface possibly mining the integrity of ground structure; (b) the integrity of the reservoir and caprock; (c) the possible reactivation of faults, if the target reservoir is located in a faulted basin; and (d) the vertical upheaval and land subsidence that can impact on the surface drainage network in low lying coastal areas. We present an original methodology for evaluating the geomechanical safety of UGS activities using an approach derived from what is traditionally applied in the structural design of buildings. A safety factor, a margin of security against risks, is defined for each of the geomechanical issues listed above. First, a 3D FE-IE numerical model is developed to reproduce the stress and displacement due to the UGS program under evaluation. Then the reservoir pressure is increased until the “failure” condition is reached allowing to evaluate how far the project designed condition is from the above limit. The proposed approach is applied to Romagna, a depleted gas reservoir in Northern Italy converted to UGS, with the aim of investigating the safety of the project to increase the reservoir pressure up to 120 % pi, where pi is the original reservoir pressure before the start of primary production. The 3D geomechanical model has been developed using recent 3D seismic data, land displacements by InSAR, lab tests on reservoir and caprock samples, in-situ Modular Formation Dynamic Tester (MDT) stress tests, and large background information acquired from other UGS reservoirs located in the same sedimentary basin. The analysis outcome has revealed that the investigated scenario is safe, with safety factor larger than 1, in the range from 1.2 to 4. The most critical condition (the smallest safety factor) has been obtained in relation to the mechanical integrity of the reservoir formation, under very conservative conditions (cohesion = 0, friction angle = 30∘).

A trans-critical carbon dioxide energy storage system with heat pump to recover stored heat of compression

In this paper, the heat pump system is used as the thermal storage system to reheat the heat of compression of the trans-critical CO2 energy storage system based on the underground gas storage reservoir, and the thermodynamic analysis and sensitivity analysis of the main equipment of the energy storage system are carried out. Considering the limitation of the thermal properties of the heat storage medium, the influence of the energy storage system composed of different heat storage medium on the system performance is studied. Results have shown that the round-trip efficiency, energy storage efficiency and heat storage efficiency of the system are 66%, 58.41%, and 46.11%, respectively. With the increase of energy storage pressure, the round-trip efficiency and energy storage efficiency increase gradually, while the heat storage efficiency decreases first and then increases. When the energy storage pressure is 23 MPa, the system has the lowest heat storage efficiency. The round-trip efficiency, energy storage efficiency and heat storage efficiency increase with the increase of the energy recovery pressure. The study also shows that the energy storage system with water as the heat storage medium has the highest efficiency and the best performance.

Utilization of CO2 as Cushion Gas for Depleted Gas Reservoir Transformed Gas Storage Reservoir

Underground gas storage reservoirs (UGSRs) are used to keep the natural gas supply smooth. Native natural gas is commonly used as cushion gas to maintain the reservoir pressure and cannot be extracted in the depleted gas reservoir transformed UGSR, which leads to wasting huge amounts of this natural energy resource. CO2 is an alternative gas to avoid this particular issue. However, the mixing of CO2 and CH4 in the UGSR challenges the application of CO2 as cushion gas. In this work, the Donghae gas reservoir is used to investigate the suitability of using CO2 as cushion gas in depleted gas reservoir transformed UGSR. The impact of the geological and engineering parameters, including the CO2 fraction for cushion gas, reservoir temperature, reservoir permeability, residual water and production rate, on the reservoir pressure, gas mixing behavior, and CO2 production are analyzed detailly based on the 15 years cyclic gas injection and production. The results showed that the maximum accepted CO2 concentration for cushion gas is 9% under the condition of production and injection for 120 d and 180 d in a production cycle at a rate of 4.05 kg/s and 2.7 kg/s, respectively. The typical curve of the mixing zone thickness can be divided into four stages, which include the increasing stage, the smooth stage, the suddenly increasing stage, and the periodic change stage. In the periodic change stage, the mixed zone increases with the increasing of CO2 fraction, temperature, production rate, and the decreasing of permeability and water saturation. The CO2 fraction in cushion gas, reservoir permeability, and production rate have a significant effect on the breakthrough of CO2 in the production well, while the effect of water saturation and temperature is limited.

Comparison of base gas replacement using nitrogen, flue gas and air during underground natural gas storage in a depleted gas reservoir

ABSTRACT Base gas is considered as an important factor in the storage operation as it remains permanently in the reservoir and maintains the reservoir pressure along the production cycle. Depending on the reservoir under consideration, base gas may occupy as little as 15% or as much as 75% of the total underground gas storage (UGS) reservoirs. Providing and injecting the cushion gas has the most contribution to the cost of the storage operations. Therefore, part of the base gas can be replaced by a cost-effective gas such as nitrogen, flue gas or air to reduce the costs of the investment. Some degree of mixing takes place when two miscible gases come into contact with one another that affects the quality of the produced natural gas. Therefore, the process needs to be studied and controlled. In this study, the feasibility of underground gas storage and the substitution of the base gas by a cheaper gas, i.e., nitrogen, flue gas, and air, are investigated in a partially depleted dry gas reservoir with very low initial pressure. To do so, a comparative study is performed among nitrogen, flue gas and air as the alternative gases to the base gas. In addition, the effect of flue gas composition on the performance of base gas replacement and ultimate gas recovery is investigated. Pure CO2 is considered as flue gas with zero mole% N2. In the end, the effect of the reservoir properties on mixing between the gases is studied. The results indicated that it is possible to substitute 24.8% of the base gas by nitrogen to obtain a 16.2% increase in the gas recovery of the reservoir. In this case, the ultimate recovery reaches 50.90%. Using flue gas as the alternative gas, the results showed a 15.6% increase in the gas recovery of the reservoir, obtained by substituting 23.9% of the base gas. The ultimate recovery using flue gas is 50.31%. According to the results, flue gas can be used as an appropriate option to replace the base gas of the UGS reservoir under consideration, and hence, there would be no more need for separation and purification of N2 and CO2. Increasing the CO2 composition in the flue gas up to 46.6 mole% leads to a decrease in the base gas replacement amount. When the composition increases above 46.6 mole%, the amount of the replaced gas does not change. However, in this composition range, more flue gas is injected into the reservoir, which has environmental advantages. The highest injection rate of the flue gas is obtained when the flue gas contains 100 mole% of CO2. The main problem in using air as the base gas is the high viscosity of air which requires a high injection pressure. According to the results, using air as the replacement gas, 21.3% of the base gas is substituted by air. In this case, gas recovery increases by 13.9% with respect to the reservoir depletion scenario and the ultimate recovery reaches 48.62%.

Source parameter analysis of microearthquakes recorded around the underground gas storage in the Montello-Collalto Area (Southeastern Alps, Italy)

The study of seismic source parameters is crucial for understanding the origin of seismicity and retrieving information on the energy balance and the stress involved in earthquake rupture processes. In active tectonic areas, where underground industrial activities are carried out, such parameters may help to understand whether earthquakes are induced, triggered, or natural. The Montello-Collalto area (Southeastern Alps) is located in an active tectonic environment and hosts a depleted natural reservoir used to store gas. Since 2012, a high-quality seismic network monitors the microseismicity occurring around the underground gas storage reservoir to understand if the storage activity might induce seismicity. In this paper, we estimate the source parameters of low magnitude events representative of the seismicity occurring in the area surrounding the reservoir. The analysis includes a preliminary removal of the site effects, specifically computed within this study, from all the records. Then, using a parametric multistep inversion scheme, we estimate the seismic moment, the corner frequency and the static stress drop, that can be set as reference for the microseismicity occurring in the study area. All the investigated earthquakes show low seismic efficiency compatible with overshoot processes, which is typical of natural (i.e., tectonic) earthquakes. Our procedure can be implemented in other tectonic regions hosting underground industrial activities to support the decisional processes related to real-time monitoring.

Combining TOUGH2 and FLAC3D to Solve Problems in Underground Gas Storage

This paper describes modeling studies assessing the feasibility of increasing the maximum storage pressure in several underground natural gas storage reservoirs. This required an assessment of the potential for gas transport in the caprock and the geomechanical response to pressure change in the storage reservoir. To solve this problem in an efficient manner, two-phase flow (TOUGH2) and geomechanical (FLAC3D) models were combined in series. The TOUGH2 model was calibrated to fit pressure data collected on-site, from both the reservoir and caprock. The mechanical response of the caprock to increased storage pressure was modeled using FLAC3D, allowing assessment of the induced stresses in formations surrounding the reservoirs. We focused on two sites. In the first, field data were obtained from a deep borehole above the gas reservoir, which provided indirect observations of the geomechanical response of the caprock to pressure changes in the reservoir. In the second, open boreholes intersecting two thin caprock units immediately above the reservoir allowed gas flow to a shallower unit, significantly impacting the modeled fracture gradient.

Key evaluation techniques in the process of gas reservoir being converted into underground gas storage

Abstract Due to the significant differences in development modes and operation rules of underground gas storage (UGS) and gas reservoir, the design of UGS construction has its own particularity and complexity. Key evaluation techniques in the process of gas reservoir being converted into underground gas storage were proposed and field application was analyzed. The construction and operation experience of the first batch commercial UGS in China was summarized, the mechanisms of multi-cycle injection and production with large flux in short-term was examined and some concepts were proposed such as the dynamic sealing of traps, the effective pore volume of UGS and the high velocity unstable seepage flow with finite supply. Four key technologies of UGS, i.e., trap sealing evaluation, gas storage parameter design, well pattern optimization and monitoring programs design were created. Preservation condition, storage capacity, effective injection & production and safe operation technology problems of UGS were solved respectively. The geological program design technology system of UGS construction in a gas field was gradually enriched and improved. These technologies have successfully guided geological plan design and implementation of UGS construction in a gas reservoir, the effects of gas storage and peaking capacity of the ramp-up cycles were great, and the actual dynamic was very consistent with design indicators.

Geological model of Lobodice underground gas storage facility based on 3D seismic interpretation

Abstract The Lobodice underground gas storage (UGS) is developed in a natural aquifer reservoir located in the Central Moravian part of the Carpathian Foredeep in the Czech Republic. In order to learn more about the UGS geological structure a 3D seismic survey was performed in 2009. The reservoir is rather shallow, 400–500 m below the surface. This article describes the process workflow from the 3D seismic field data acquisition to the creation of the geological model. The outcomes of this workflow define the geometry of the UGS reservoir, its tectonics and the sealing features of the structure. Better geological knowledge of the reservoir will reduce the risks involved in the localization of new wells for increasing UGS withdrawal rates.

Finite Element Optimised Back Analysis of In Situ Stress Field and Stability Analysis of Shaft Wall in the Underground Gas Storage

A novel optimised back analysis method is proposed in this paper. The in situ stress field of an underground gas storage (UGS) reservoir in a Turkey salt cavern is analysed by the basic theory of elastic mechanics. A finite element method is implemented to optimise and approximate the objective function by systematically adjusting boundary loads. Optimising calculation is performed based on a novel method to reduce the error between measurement and calculation as much as possible. Compared with common back analysis methods such as regression method, the method proposed can further improve the calculation precision. By constructing a large circular geometric model, the effect of stress concentration is eliminated and a minimum difference between computed and measured stress can be guaranteed in the rectangular objective region. The efficiency of the proposed method is investigated and confirmed by its capability on restoring in situ stress field, which agrees well with experimental results. The characteristics of stress distribution of chosen UGS wells are obtained based on the back analysis results and by applying the corresponding fracture criterion, the shaft walls are proven safe.

Comparison of nitrogen and carbon dioxide as cushion gas for underground gas storage reservoir

Using nitrogen and carbon dioxide as cushion gases can bring economic profit due to their cheap costs. However, the different properties of these gases cause differences in behavior when operating in underground gas storage (UGS). In particular, the mass density of nitrogen gas is similar to methane, while carbon dioxide is much heavier than methane in reservoir conditions. These differences cause loss of inert gas or productivity to vary. From this perspective, it is crucial to analyze the behavior of nitrogen and carbon dioxide during the operation of UGS reservoir. The purpose of this study is to evaluate loss of inert gas of injected gas and to determine productivity according to different cushion gases. A simulation research was performed to compare the effects of nitrogen and carbon dioxide and their behavior. The results showed that nitrogen has less loss of inert gas than carbon dioxide, but reduced productivity compared with carbon dioxide.

Investigating the effect of fracture–matrix interaction in underground gas storage process at condensate naturally fractured reservoirs

Depleted oil and gas reservoirs are used for underground gas storage. Accurate prediction of fractured reservoir efficiency during storage period is of great importance due to complex phase behavior of fluids and existence of fractures. The reservoir model should be representative of the reservoir behavior, the interaction between fracture and matrix and it should be capable of exact prediction of reservoir deliverability.Despite comprehensive studies performed on fractured reservoirs, the effect of fracture–matrix interaction on underground gas storage capacity and reservoir injectivity is not yet investigated. In this paper, the role of fracture on storage capacity and fluid distribution is determined by investigating the behavior of a fractured gas condensate reservoir using different models during gas storage. The single-porosity compositional model of a real reservoir is constructed and validated. The reservoir is simulated using dual-porosity and dual-permeability models and reservoir performance is compared for different storage periods.The primary objective of this study is to determine the fracture influence on fractured reservoir simulation, as compared to matrix in underground gas storage. The water production, gas invasion in the reservoir during injection, condensate production, and relative permeability which are known to have high impact on the gas behavior are all affected by the changes in the system used for model construction. The results of this study show that although petrophysical properties, the volume of gas in place, and reservoir pressure drop are the same during reservoir depletion, different storage capacities and injectivity are predicted in gas storage periods. Fractures result in wider spread of injected gas (improvement of injected gas invasion) in the field and gas movement is easier during injection and production periods, mainly owing to the absence of water in fractures.

Purposefully built underground natural gas storage

The volumes of natural gas that are needed for a wide variety of industrial processes plus domestic uses vary significantly with respect to time, location, and demand. Thus, mechanical storage of natural gas in manufactured containers is not economically feasible or even logistically possible. Although much of the storage and withdrawal have been associated with seasonality, storage is becoming essential in an integrated natural gas supply network. It is particularly important in large operations, such as being a backup fuel in power generation and in sustaining the rate for liquefied natural gas (LNG) production. Therefore, the design of underground natural gas storage becomes essential.Important components of natural gas storage engineering include capacity which is affected by reservoir volume and tolerable pressure; injection or producing rates which are affected by reservoir permeability, natural reservoir drive mechanism, well completion/stimulation; and the impact of cyclical losses.We present here a new sequence of calculations and estimations for monitoring and forecasting gas movements through an underground gas storage reservoir:• Maximum capacity estimation with a new type of graphical construction, blending concepts of the classical p/Z vs. cumulative recovery straight line in natural gas production.• Prediction of withdrawal rates and time, constrained by decreasing storage pressure.• Determination of maximum or sustainable withdrawal rate for a period of time. In all cases considered, the injecting and producing wells are hydraulically fractured. The hydraulic fractures are designed for the withdrawal rate. Thus, the required number of wells is determined.We apply these concepts to an underground natural gas storage facility and forecast the injection and production rates, cumulative storage and withdrawal, pressure buildup and decline as a function of time.A case study is presented here to demonstrate an appropriate sequence for designing an underground natural gas storage facility so that it can meet certain functionalities. In this case, the underground storage facility needs to provide enough gas to support a 1000 MW gas-fired power plant for continuous 90-day operating period (in the case of emergency).

An advanced algorithm for deformation estimation in non-urban areas

This paper presents an advanced differential SAR interferometry stacking algorithm for high resolution deformation monitoring in non-urban areas with a focus on distributed scatterers (DSs). Techniques such as the Small Baseline Subset Algorithm (SBAS) have been proposed for processing DSs. SBAS makes use of small baseline differential interferogram subsets. Singular value decomposition (SVD), i.e. L2 norm minimization is applied to link independent subsets separated by large baselines. However, the interferograms used in SBAS are multilooked using a rectangular window to reduce phase noise caused for instance by temporal decorrelation, resulting in a loss of resolution and the superposition of topography and deformation signals from different objects. Moreover, these have to be individually phase unwrapped and this can be especially difficult in natural terrains. An improved deformation estimation technique is presented here which exploits high resolution SAR data and is suitable for rural areas. The implemented method makes use of small baseline differential interferograms and incorporates an object adaptive spatial phase filtering and residual topography removal for an accurate phase and coherence estimation, while preserving the high resolution provided by modern satellites. This is followed by retrieval of deformation via the SBAS approach, wherein, the phase inversion is performed using an L1 norm minimization which is more robust to the typical phase unwrapping errors encountered in non-urban areas. Meter resolution TerraSAR-X data of an underground gas storage reservoir in Germany is used for demonstrating the effectiveness of this newly developed technique in rural areas.