The role of supercritical CO2 in gas well health issue – liquid loading

2020 ◽  
Vol 60 (1) ◽  
pp. 143
Author(s):  
Bashirul Haq ◽  
Fahad Shehiwin ◽  
Dhafer Al Shehri ◽  
Jishan Liu ◽  
Nasiru Muhammed ◽  
...  
Keyword(s):  
Surface Tension ◽  
Supercritical Co2 ◽  
Co2 Storage ◽  
Health Issue ◽  
Co2 Injection ◽  
Liquid Loading ◽  
Well Productivity ◽  
Liquid Load ◽  
The Impact

Liquid load or condensate banking is a common well health issue in gas/gas-condensate reservoirs that decreases well productivity by a factor of two to four. Due to the depletion of bottom-hole pressure, the produced liquid accumulates around the wellbore and creates a static column of liquid that reduces gas production until well production ceases. Enhancing gas recovery by CO2 injection is a promising technology because it reduces greenhouse gas emissions and improves CO2 storage. More investigation needs to be conducted to understand the role of supercritical CO2 (SCCO2) in minimising liquid loading. The aim of this research is to examine the impact of SCCO2 in surface tension, condensate viscosity and well productivity. This study consists of simulation and laboratory experiments. Eclipse 300 was used to develop a model that examines the effect of SCCO2 injection on reducing liquid loading issues by varying the well parameters. We found that injecting SCCO2 improved the microscopic displacement efficiency and minimised liquid loading by decreasing the condensate viscosity and the surface tension. The model shows that (1) condensate recovery increases when the injection rate increases up to a limit after which there is no change of production and (2) condensate recovery improves with decreasing production rate.

scholarly journals Experimental Investigation of the Mechanisms of Salt Precipitation during CO2 Injection in Sandstone

2019 ◽  
Vol 5 (1) ◽  
pp. 4 ◽  
Author(s):  
Yen Adams Sokama-Neuyam ◽  
Jann Rune Ursin ◽  
Patrick Boakye
Keyword(s):  
Co2 Storage ◽  
Simulation Models ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Physical Mechanisms ◽  
Low Salinity ◽  
Core Flood ◽  
Dry Out ◽  
The Impact ◽  
Brine Salinity

Deep saline reservoirs have the highest volumetric CO2 storage potential, but drying and salt precipitation during CO2 injection could severely impair CO2 injectivity. The physical mechanisms and impact of salt precipitation, especially in the injection area, is still not fully understood. Core-flood experiments were conducted to investigate the mechanisms of external and internal salt precipitation in sandstone rocks. CO2 Low Salinity Alternating Gas (CO2-LSWAG) injection as a potential mitigation technique to reduce injectivity impairment induced by salt precipitation was also studied. We found that poor sweep and high brine salinity could increase salt deposition on the surface of the injection area. The results also indicate that the amount of salt precipitated in the dry-out zone does not change significantly during the drying process, as large portion of the precipitated salt accumulate in the injection vicinity. However, the distribution of salt in the dry-out zone was found to change markedly when more CO2 was injected after salt precipitation. This suggests that CO2 injectivity impairment induced by salt precipitation is probably dynamic rather than a static process. It was also found that CO2-LSWAG could improve CO2 injectivity after salt precipitation. However, below a critical diluent brine salinity, CO2-LSWAG did not improve injectivity. These findings provide vital understanding of core-scale physical mechanisms of the impact of salt precipitation on CO2 injectivity in saline reservoirs. The insight gained could be implemented in simulation models to improve the quantification of injectivity losses during CO2 injection into saline sandstone reservoirs.

Pore–Scale Numerical Investigations of the Impact of Mineral Dissolution and Transport in Naturally Fractured Systems During CO2–Enriched Brine Injection

2021 ◽  
Author(s):  
Jiahui You ◽  
Kyung Jae Lee
Keyword(s):  
Dissolution Rate ◽  
Co2 Storage ◽  
Mineral Dissolution ◽  
Initial Time ◽  
Co2 Injection ◽  
Pore Scale ◽  
Acid Rock ◽  
Rock Interaction ◽  
Connected Area ◽  
The Impact

Abstract CO2 storage and sequestration are regarded as an effective approach to mitigate greenhouse gas emissions. While injecting an enormous amount of CO2 into carbonate–rich aquifers, CO2 dissolves in the formation brine under the large pressure, and the subsequently formed CO2–enriched brine reacts with the calcite. Reaction–induced changes in pore structure and fracture geometry alter the porosity and permeability, giving rise to concerns of CO2storage capacity and security. Especially in the reservoir or aquifer with natural fractures, the fractures provide a highly permeable pathways for fluid flow. This study aims to analyze the acid–rock interaction and subsequent permeability evolution in the systems with complex fracture configurations during CO2 injection by implementing a pore–scale DBS reactive transport model. The model has been developed by expanding the functionality of OpenFOAM, which is an open–source code for computational fluid dynamics. A series of partial differential equations are discretized by applying the Finite Volume Method (FVM) and sequentially solved. Different fracture configurations in terms of fracture length, density, connection, and mineral components have been considered to investigate their impacts on the dynamic porosity–permeability relationship, dissolution rate, and reactant transport characteristics during CO2 storage. The investigation revealed several interesting findings. We found that calcium (Ca) concentration was low in the poorly connected area at the initial time. As CO2–enriched brine saturated the system and reacted with calcite, Ca started being accumulated in the system. However, Ca barely flowed out of the poor–connected area, and the concentration became high. Lengths of branches mainly influenced the dissolution rates, while they had slight impacts on the porosity–permeability relationship. While fracture connectivity had an apparent influence on the porosity–permeability relationship, it showed a weak relevance on the dissolution rate. These microscopic insights can help enhance the CO2 sealing capacity and guarantee environmental security.

Geochemistry monitoring of CO2 storage at the CO2CRC Otway Project, Victoria: operational mode

2009 ◽  
Vol 49 (2) ◽  
pp. 602
Author(s):  
Chris Boreham ◽  
Jim Underschultz ◽  
Linda Stalker ◽  
Barry Freifeld ◽  
Dirk Kirste ◽  
...  
Keyword(s):  
Supercritical Co2 ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Operational Mode ◽  
Water Contact ◽  
Tracer Injection ◽  
Flow Models ◽  
Chemical Tracers ◽  
Tube Assembly ◽  
Operational Issues

The CO2CRC Otway Project is an Australian-first, demonstration-scale CO2 geosequestration experiment. It incorporates a wide-ranging monitoring and verification operation, including the injection of chemical tracers and the geochemical characterisation of the subsurface fluids sampled from the Naylor—1 monitoring well multi-zone U-tube system. Following the successful collection of baseline gas and fluid samples, injection began in April 2008 and by September 2008 over 20,000 tonnes of the projected total of ∼100,000 tonnes of supercritical CO2 has been injected into the depleted Waarre C unit of the Naylor gas reservoir in the Otway Basin. Critical operational issues revolved around the timing of the chemical tracer injection at the CRC—1 injection well and the on-going maintenance and modifications to the U-tube sampling assembly. The latter resulted from two things:a hazard and operability study (HAZOP), which specifically addressed the continued integrity of the U-tube assembly and the safe collection and disposal of pressurised gases and formation waters, and the need for an innovative solution to mitigate against hydrocarbon wax precipitaton inside the U-tubes that would have jeopardise retrieval of sub-surface samples. A solvent delivery and retrieval system involving Solvesso—100TM was deployed following a mini-HAZOP. Breakthrough was initially confirmed by tracer detection at Naylor—1 approximately four months after injection began, whereas changes in the inorganic geochemical signatures were observed a few weeks later. This has validated the sub-surface monitoring strategy and resulted in refinements to fluid flow models and expanded our understanding of geochemical processes. Furthermore, supercritical CO2 injection has resulted in the lowering of the gas-water contact at Naylor—1 and the progressive gassing out of the deeper U-tubes. Weekly to fortnightly U-tube sampling will continue until supercritical CO2 is established at Naylor—1 following which the frequency of sampling will be reviewed for the rest of the injection period.

Impact of faults and compartmentalisation on geological carbon storage estimates in highly faulted basins

2017 ◽  
Vol 57 (2) ◽  
pp. 789
Author(s):  
Jorik W. Poesse ◽  
Ludovic P. Ricard ◽  
Allison Hortle
Keyword(s):  
Carbon Storage ◽  
Storage Capacity ◽  
Co2 Storage ◽  
Fault Reactivation ◽  
Hydrocarbon Exploration ◽  
Co2 Injection ◽  
Exploration And Production ◽  
Order Of Magnitude ◽  
Fault Permeability ◽  
The Impact

Faults have extensively been studied for hydrocarbon exploration and production; however, previous studies on fault behaviour for geological carbon storage have focused on sealing capacity or reactivation potential during injection or post-injection phases. Little is known on the impact of faults for estimating storage capacity in highly faulted basins. A geological conceptual model of a representative compartment was designed to identify the key drivers of storage capacity estimates in highly faulted basins. An uncertainty quantification framework was then designed upon this model to address the impact of geological uncertainties such as fault permeability, reservoir injectivity, compartment geometry and closure on the compartment storage capacity. Pressure-limited storage capacity was estimated from numerical simulation of CO2 injection under the constraints of maximum bottom hole pressure and fault reactivation pressure. Interpretation of the simulation results highlights that (1) two injection regimes are observed: borehole- or fault-controlled, (2) storage capacity can vary more than an order of magnitude, (3) fault and reservoir permeability can be regarded as the most influential properties with respect to storage capacity, (4) compartment geometry mainly influences the injection regime controlling the storage capacity and (5) the large sensitivity of storage capacity to the type of enclosure and fault permeability indicates that pressure build-up at the fault is often the deciding factor for CO2 storage capacity.

scholarly journals Modelling of CO2 Injection in Fluvial Sedimentary Heterogeneous Reservoirs to Assess the Impact of Geological Heterogeneities on CO2 Storage Capacity and Performance

2013 ◽  
Vol 37 ◽  
pp. 5181-5190 ◽  
Author(s):  
Benoît Issautier ◽  
Simon Fillacier ◽  
Yann Le Gallo ◽  
Pascal Audigane ◽  
Christophe Chiaberge ◽  
...  
Keyword(s):  
Storage Capacity ◽  
Co2 Storage ◽  
Co2 Injection ◽  
Heterogeneous Reservoirs ◽  
And Performance ◽  
The Impact

Offshore MMV Planning for Sustainability of CO2 Storage in a Depleted Carbonate Reservoir, Malaysia

2021 ◽  
Author(s):  
Pankaj Kumar Tiwari ◽  
Debasis Priyadarshan Das ◽  
Parimal Arjun Patil ◽  
Prasanna Chidambaram ◽  
Zoann Low ◽  
...  
Keyword(s):  
Co2 Sequestration ◽  
Co2 Storage ◽  
Carbonate Reservoir ◽  
Co2 Injection ◽  
Storage Site ◽  
Gas Field ◽  
Plume Migration ◽  
Co2 Plume ◽  
The Impact

Abstract CO2 sequestration is a process for eternity with a possibility of zero-degree failure. Monitoring, Measurement and Verification (MMV) planning of CO2 sequestration is crucial along with geological site selection, transportation and injection process. Several geological formations have been evaluated in the past for potential storage site which divulges the containment capacity of identified large, depleted gas reservoirs as well as long term conformance. Offshore environment makes MMV plan challenging and demands rigorous integration of monitoring technologies to optimize project economic and involved logistics. The role of MMV is critical for sustainability of the CO2 storage project as it ensures that injected CO2 in the reservoir is intact and safely stored for hundreds of years post-injection. Field specific MMV technologies for CO2 plume migration with proactive approach were identified after exercising pre-defined screening criteria. Marine CO2 dispersion study is carried out to confirm the impact of any potential leakage along existing wells and faults, and to understand the CO2 behavior in marine environment in the event of leakage. Study incorporates integration of G&G subsurface and Meta-Ocean & Environment data along with other leakage character information. Multi-Fiber Optic Sensors System (M-FOSS) to be installed in injector wells for monitoring well & reservoir integrity, overburden integrity and monitoring of early CO2 plume migration by acquiring & analyzing the distributed sensing data (DTS/DPS/DAS/DSS). Based on 3D couple modeling, a maximum injection rate of approximately 200 MMscfd of permeate stream produced from a high CO2 contaminated gas field can be achieved. Injectivity studies indicate that over 100 MMSCFD of CO2 injection rates into depleted gas reservoir is possible from a single injector. Injectivity results are integrated with dynamic simulation to determine number and location of injector wells. 3D DAS-VSP simulation results show that a subsurface coverage of approximately 3 km2 per well is achievable, which along with simulated CO2 plume extent help to determine the number of wells required to get maximum monitoring coverage for the MMV planning. As planned injector wells are field centric and storage site area is large, DAS-VSP find limited coverage to monitor the CO2 plume. To overcome this challenge, requirement of surface seismic acquisition survey is recommended for full field monitoring. An integrated MMV plan is designed for cost-effective long-term offshore monitoring of CO2 plume migration. The present study discusses the impacting parameters which make the whole process environmentally sustainable, economically viable and adhering to national and international regulations.

Effect of the number of water alternating CO2 injection cycles on CO2 trapping capacity

2019 ◽  
Vol 59 (1) ◽  
pp. 357 ◽  
Author(s):  
Emad A. Al-Khdheeawi ◽  
Stephanie Vialle ◽  
Ahmed Barifcani ◽  
Mohammad Sarmadivaleh ◽  
Stefan Iglauer
Keyword(s):  
Storage Capacity ◽  
Co2 Storage ◽  
Storage Period ◽  
Co2 Injection ◽  
Co2 Leakage ◽  
Storage Efficiency ◽  
Reservoir Model ◽  
Plume Migration ◽  
The Impact ◽  
Injection Cycle

The CO2 storage capacity is greatly affected by CO2 injection scenario – i.e. water alternating CO2 (WACO2) injection, intermittent injection, and continuous CO2 injection – and WACO2 injection strongly improves the CO2 trapping capacity. However, the impact of the number of WACO2 injection cycles on CO2 trapping capacity is not clearly understood. Thus, we developed a 3D reservoir model to simulate WACO2 injection in deep reservoirs testing different numbers of WACO2 injection cycles (i.e. one, two, and three), and the associated CO2 trapping capacity and CO2 plume migration were predicted. For all different WACO2 injection cycle scenarios, 5000 kton of CO2 and 5000 kton of water were injected at a depth of 2275m and 2125m respectively, during a 10-year injection period. Then, a 100-year CO2 storage period was simulated. Our simulation results clearly showed, after 100 years of storage, that the number of WACO2 cycles affected the vertical CO2 leakage and the capacity of trapped CO2. The results showed that increasing the number of WACO2 cycles decreased the vertical CO2 leakage. Furthermore, a higher number of WACO2 cycles increased residual trapping, and reduced solubility trapping. Thus, the number of WACO2 cycles significantly affected CO2 storage efficiency, and higher numbers of WACO2 cycles improved CO2 storage capacity.

Intergroup Threat and Outgroup Attitudes

2013 ◽  
Vol 44 (5) ◽  
pp. 311-319 ◽  
Author(s):  
Marco Brambilla ◽  
David A. Butz
Keyword(s):  
Gay Men ◽  
Social Group ◽  
Welfare Recipients ◽  
Intergroup Attitudes ◽  
Social Policies ◽  
Intergroup Threat ◽  
Economic Threat ◽  
The Impact ◽  
General Climate

Two studies examined the impact of macrolevel symbolic threat on intergroup attitudes. In Study 1 (N = 71), participants exposed to a macrosymbolic threat (vs. nonsymbolic threat and neutral topic) reported less support toward social policies concerning gay men, an outgroup whose stereotypes implies a threat to values, but not toward welfare recipients, a social group whose stereotypes do not imply a threat to values. Study 2 (N = 78) showed that, whereas macrolevel symbolic threat led to less favorable attitudes toward gay men, macroeconomic threat led to less favorable attitudes toward Asians, an outgroup whose stereotypes imply an economic threat. These findings are discussed in terms of their implications for understanding the role of a general climate of threat in shaping intergroup attitudes.

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