Seismicity Induced by Simultaneous Abrupt Changes of Injection Rate and Well Pressure in Hutubi Gas Field

Abstract For deepwater subsea tie-back gas field development, hydrate tends to be formed in deepwater subsea production system and gas pipeline due to high pressure and low temperature. Based on the gas field A development, this paper studies the selection of hydrate inhibitors and injection points, i.e. different injection points with different inhibitors. Transient and steady flow simulations are performed using the OLGA software widely used for multiphase flow pipeline study in the world. The produced water flow rate affects the hydrate inhibition in case of well opening, including cases of different times with different water temperatures. This paper presents the calculation of the maximum inhibitor injection rate in the subsea pipeline by taking the whole production years into consideration. The measures on hydrate remediation are taken by quickly relieving the subsea pipeline pressure from wellheads and the platform according to different hydrate locations. Now more and more deepwater gas fields are developed in South China Sea and around the world. The experience obtained from the gas field A development will benefit the hydrate inhibition for future deepwater gas field development.

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Did Wastewater Disposal Drive the Longest Seismic Swarm Triggered by Fluid Manipulations? Lacq, France, 1969–2016

Bulletin of the Seismological Society of America ◽

10.1785/0120200359 ◽

2021 ◽

Author(s):

Jean-Robert Grasso ◽

Daniel Amorese ◽

Abror Karimov

Keyword(s):

Injection Rate ◽

Injection Well ◽

Gas Reservoir ◽

Gas Field ◽

Wastewater Disposal ◽

Seismic Swarm ◽

Stress Changes ◽

Changepoint Analysis ◽

Poroelastic Model ◽

Fluid Manipulation

ABSTRACT The activation of tectonics and anthropogenic swarms in time and space and size remains challenging for seismologists. One remarkably long swarm is the Lacq swarm. It has been ongoing since 1969 and is located in a compound oil–gas field with a complex fluid manipulation history. Based on the overlap between the volumes where poroelastic model predicts stresses buildup and those where earthquakes occur, gas reservoir depletion was proposed to control the Lacq seismic swarm. The 2016 Mw 3.9, the largest event on the site, is located within a few kilometers downward the deep injection well. It questions the possible interactions between the 1955–2016 wastewater injections and the Lacq seismicity. Revisiting 60 yr of fluid manipulation history and seismicity indicates that the impacts of the wastewater injections on the Lacq seismicity were previously underevaluated. The main lines of evidence toward a wastewater injection cause are (1) cumulative injected volume enough in 1969 to trigger Mw 3 events, onset of Lacq seismicity; (2) 1976 injection below the gas reservoir occurs only a few years before the sharp increase in seismicity. It matches the onset of deep seismicity (below the gas reservoir, at the injection depth); (3) the (2007–2010) 2–3 folds increase in injection rate precedes 2013, 2016 top largest events; and (4) 75% of the 2013–2016 events cluster within 4–8 km depths, that is, close to and downward the 4.5 km deep injection well. As quantified by changepoint analysis, our results suggest that timely overlaps between injection operations and seismicity patterns are as decisive as extraction operations to control the Lacq seismicity. The seismicity onset is contemporary to cumulative stress changes (induced by depletion and injection operations) in the 0.1–1 MPa range. The interrelation between injection and extraction is the most probable cause of the Lacq seismicity onset and is sustenance over time. The injected volume–largest magnitude pair for Lacq field is in the same range (90% confidence level) than wastewater volume–magnitude pairs reported worldwide, in a wide variety of tectonic settings.

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Numerical Study of Simultaneous Multiple Fracture Propagation in Changning Shale Gas Field

Energies ◽

10.3390/en12071335 ◽

2019 ◽

Vol 12 (7) ◽

pp. 1335 ◽

Cited By ~ 3

Author(s):

Jun Xie ◽

Haoyong Huang ◽

Yu Sang ◽

Yu Fan ◽

Juan Chen ◽

...

Keyword(s):

Shale Gas ◽

Fracture Propagation ◽

Injection Rate ◽

Propagation Model ◽

Fluid Viscosity ◽

Multiple Fracture ◽

Gas Field ◽

Fracture Spacing ◽

Stress Shadow ◽

Engineering Parameters

Recently, the Changning shale gas field has been one of the most outstanding shale plays in China for unconventional gas exploitation. Based on the more practical experience of hydraulic fracturing, the economic gas production from this field can be optimized and gradually improved. However, further optimization of the fracture design requires a deeper understanding of the effects of engineering parameters on simultaneous multiple fracture propagation. It can increase the effective fracture number and the well performance. In this paper, based on the Changning field data, a complex fracture propagation model was established. A series of case studies were investigated to analyze the effects of engineering parameters on simultaneous multiple fracture propagation. The fracture spacing, perforating number, injection rate, fluid viscosity and number of fractures within one stage were considered. The simulation results show that smaller fracture spacing implies stronger stress shadow effects, which significantly reduces the perforating efficiency. The perforating number is a critical parameter that has a big impact on the cluster efficiency. In addition, one cluster with a smaller perforating number can more easily generate a uniform fracture geometry. A higher injection rate is better for promoting uniform fluid volume distribution, with each cluster growing more evenly. An increasing fluid viscosity increases the variation of fluid distribution between perforation clusters, resulting in the increasing gap between the interior fracture and outer fractures. An increasing number of fractures within the stage increases the stress shadow among fractures, resulting in a larger total fracture length and a smaller average fracture width. This work provides key guidelines for improving the effectiveness of hydraulic fracture treatments.

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Preliminary Numerical Modeling of CO2 Geological Storage in the Huangcaoxia Gas Reservoir in the Eastern Sichuan Basin, China

Geofluids ◽

10.1155/2019/9545723 ◽

2019 ◽

Vol 2019 ◽

pp. 1-23

Author(s):

Hongwu Lei ◽

Qian Zhang ◽

Xiaochun Li

Keyword(s):

Sichuan Basin ◽

Temperature Drop ◽

Injection Pressure ◽

Injection Rate ◽

Gas Production ◽

Injection Well ◽

Gas Reservoir ◽

Gas Field ◽

Eastern Sichuan Basin ◽

Eastern Sichuan

Depleted gas reservoirs are important potential sites for CO2 geological sequestration due to their proven integrity and safety, well-known geological characteristics, and existing infrastructures and wells built for natural gas production. The Sichuan Basin has a large number of gas fields in which approximately 5.89×109 tons of CO2 can be stored. The Huangcaoxia gas field has the best opportunity in the eastern Sichuan Basin for a pilot project of CO2 sequestration due to its relatively large storage capacity and the nearly depleted state. A coupled thermal-hydrodynamic model including faults is built based on the geological and hydrogeological conditions in the Huangcaoxia gas field. The results of the numerical simulations show that the downhole temperature is above 80°C at a downhole pressure of 14 MPa under the constraint of temperature drop in the reservoir due to the strong Joule-Thomson effect. The corresponding injection pressure and temperature at the wellhead are 10.5 MPa and 60°C, respectively. The sizes of the pressure and CO2 plumes after an injection of 10 years are 18 km and 5 km, respectively. The zone affected by temperature change is very small, being about 1-2 km away from the injection well. The injection rate in the injection well Cao 31 averages 6.89 kg/s (21.73×104 tons/a). For a commercial-scale injection, another four wells (Cao 9, Cao 30, Cao 6, and Cao 22) can be combined with the Cao 31 well for injection, approaching an injection rate of 35 kg/s (1.10×106 tons/a). Both the pressure and temperature of CO2 injection decrease with the increasing depleted pressure in the gas reservoir when the latter is below 6 MPa. With the technique of CO2-enhanced gas recovery (CO2-EGR), the CO2 injection rate is improved and approximately 1.58×107 kg of gas can be produced during a studied time period of 10 years.

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Laboratory and Field Evaluation of Aqueous Retarded Acid System for Carbonate Gas Field, Offshore Borneo Island

10.2118/207961-ms ◽

2021 ◽

Author(s):

Tenamutha Ravichandran ◽

Sulaiman Sidek ◽

Ahmed Nabil Zakaria ◽

Karim Ahmed Shata ◽

Zool Nasri Sapiee ◽

...

Keyword(s):

Laboratory Testing ◽

Injection Rate ◽

Field Application ◽

Carbonate Reservoir ◽

Production Performance ◽

Reservoir Rock ◽

Sensitivity Analyses ◽

Acid System ◽

Software Modeling ◽

Gas Field

Abstract Objectives, Scope This paper provides valuable insights on aqueous retarded acid system evaluation based on laboratory testing, literature review and engineering analysis prior to the field application for a candidate well in a gas field, offshore East Malaysia (Figure 1). The field is a reefal carbonates build-up overlayed by a thick shale sequence and is one of the deepest fields in Sarawak Asset, in which the produced fluid contains up to 3,500ppm H2S, 20% CO2 and bottomhole temperature up to 288°F. Production enhancement for this carbonate reservoir requires application of a more effective approach to address challenges associated with acid placement and reservoir contact in long pay zones of complex diagenetic facies high temperature carbonate reservoirs, thereby improving return on investment. Figure 1Structural map of Central Luconia carbonate platform offshore Sarawak, Malaysia (Janjuhah et al. 2016) Methods, Procedures, Process The workflow adopted for the stimulation job involves thorough historical production data analysis, detail petrophysical review to evaluate reservoir properties, in-depth production performance analysis (i.e. nodal and network modeling), completion review to ascertain damage mechanism and economic evaluation that include decision risk analysis to evaluate all range of probabilistic outcome. Initial selection of stimulation fluids was based on the mineralogical composition of the main producing formation. A detailed study of reservoir rock and its reaction to various acid systems has been based upon software modeling where sensitivity analyses involving multiple treatment schedule scenarios incorporating various acid and diverter fluid systems are considered. Coreflood experiment was then performed to determine the Pore Volume to Breakthrough (PVBT) comparing emulsified acid with aqueous retarded acid at temperature of 250°F, injection rate of 3ml/min and at confining pressure of 1,500psi. The low PVBT values (i.e. 1.125 and 0.521) and unique breakthrough features obtained from the coreflood confirmed that aqueous retarded acid is effective to stimulate the carbonate reservoir. Compatibility testing was also conducted to assess the stability of the retarded acid recipes and potential reaction with reservoir fluids (i.e. water and condensate), downhole completion and surface equipment. Results, Observation, Conclusion An established stimulation software was used to refine the acid volume calculation and placement analysis. Field trial was made using combined application of the aqueous retarded acid and viscoelastic diverting acid. Considering several case scenarios, the remedial treatment was performed via bullheading to achieve optimum injection rate within 5bpm to 7bpm. Total of 197bbls acid and 197bbls diverter was be pumped during the treatment that will be split in several stages to achieve average invasion profile of 2.8ft and -1.3 skin value. This paper presents aqueous retarded acid system as alternative to widely used emulsified acid systems. Field application of the approach supports the theoretical findings based on substantial improvement in well production, pressure matching of the remedial treatment and calibrated nodal analysis assessment. This demonstrates the value of holistic approach of laboratory testing, comprehensive software modeling and application of enhanced stimulation fluids to overcome complex technical challenges Novel, Additive Information The field production was previously constrained by its high CO2 levels and the supply gas ratio agreement. The information and lessons learnt from this paper will be applicable as evident of practical improvements to achieve sustainable production from the field since it has a strategic importance as production, processing and export hub to other four gas fields. Recent CO2 blending project has allow a better distribution of gas across the network and therefore demand higher production from the field, thus further unlock it potential to achieve economic optimization.

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Underground Gas Storage With CO2 Sequestration in a Depleted Gas Field

Volume 8: Polar and Arctic Sciences and Technology; Petroleum Technology ◽

10.1115/omae2016-54224 ◽

2016 ◽

Author(s):

Juhyeon Kim ◽

Sunlee Han ◽

Gilyong Sung ◽

Youngsoo Lee

Keyword(s):

Critical Factor ◽

Cost Effective ◽

Gas Storage ◽

Injection Rate ◽

Optimal Number ◽

Transport Infrastructure ◽

Co2 Production ◽

Underground Gas Storage ◽

Gas Field ◽

Economic Point

In this study, simulation research was performed in order to switch producing gas field over to UGS (Underground Gas Storage). Generally, a large amount of cushion gas that is mainly composed of CH4 is required to maintain the enough pressure in the UGS reservoir and it cannot be produced during the UGS operation. If there is an alternative way to mitigate the volume of cushion gas, more cost-effective operation is possible. In this reason, we injected CO2 as a cushion gas and determined optimal number of wells and injection/withdrawal rate without CO2 production. The reservoir opportunity index was used to select the target drilling points. The proper volume of working and cushion gas were obtained respectively in various gas rate case. As a result, injected CO2 can supply additional pressure to the reservoir that more effective UGS operation is possible. And injection rate is a critical factor for the stable working gas injection and production from the economic point of view. Also, a design for a complete CCS system was developed based on the existing off-shore pipeline in combination with new on-shore CO2 transport infrastructure.

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