scholarly journals Geysers Valley CO2 Cycling Geological Engine (Kamchatka, Russia)

Geofluids ◽  
2018 ◽  
Vol 2018 ◽  
pp. 1-16 ◽  
Author(s):  
A. Kiryukhin ◽  
V. Sugrobov ◽  
E. Sonnenthal
Keyword(s):  
Water Discharge ◽  
Water Injection ◽  
Geothermal Reservoir ◽  
Chemical Components ◽  
Natural State ◽  
Water Influx ◽  
Chemical History ◽  
Valley Of Geysers ◽  
Giant Landslide ◽  
Gas Lift

1941–2017 period of the Valley of Geysers monitoring (Kamchatka, Kronotsky Reserve) reveals a very dynamic geyser behavior under natural state conditions: significant changes of IBE (interval between eruptions) and power of eruptions, chloride and other chemical components, and preeruption bottom temperature. Nevertheless, the total deep thermal water discharge remains relatively stable; thus all of the changes are caused by redistribution of the thermal discharge due to giant landslide of June 3, 2007, mudflow of Jan. 3, 2014, and other events of geothermal caprock erosion and water injection into the geothermal reservoir. In some cases, water chemistry and isotope data point to local meteoric water influx into the geothermal reservoir and geysers conduits. TOUGHREACT V.3 modeling of Velikan geyser chemical history confirms 20% dilution of deep recharge water and CO2 components after 2014. Temperature logging in geysers Velikan (1994, 2007, 2015, 2016, and 2017) and Bolshoy (2015, 2016, and 2017) conduits shows preeruption temperatures below boiling at corresponding hydrostatic pressure, which means partial pressure of CO2 creates gas-lift upflow conditions in geyser conduits. Velikan geyser IBE history explained in terms of gradual CO2 recharge decline (1941–2013), followed by CO2 recharge significant dilution after the mudflow of Jan. 3, 2014, also reshaped geyser conduit and diminished its power.

The Emerald Field, Blocks 2/10a, 2/15a, 3/11b, UK North Sea

1991 ◽  
Vol 14 (1) ◽  
pp. 111-116 ◽  
Author(s):  
D. M. Stewart ◽  
A. J. G. Faulkner
Keyword(s):  
North Sea ◽  
Water Injection ◽  
Maximum Flow ◽  
Oil Field ◽  
Injection Wells ◽  
Initial Development ◽  
Flexible Risers ◽  
Northern North Sea ◽  
The Uk ◽  
Gas Lift

AbstractThe Emerald Oil Field lies in Blocks 2/10a, 2/15a and 3/1 lb in the UK sector of the northern North Sea. The field is located on the 'Transitional Shelf, an area on the western flank of the Viking Graben, downfaulted from the East Shetland Platform. The first well was drilled on the structure in 1978. Subsequently, a further seven wells have been drilled to delineate the field.The Emerald Field is an elongate dip and fault closed structure subparallel to the local NW-SE regional structural trend. the 'Emerald Sandstone' forms the main reservoir of the field and comprises a homogeneous transgressive unit of Callovian to Bathonian age, undelain by tilted Precambrian and Devonian Basement Horst blocks. Sealing is provided by siltstones and shales of the overlying Healther and Kimmeridge Clay Formations. The reservoir lies at depths between 5150-5600 ft, and wells drilled to date have encountered pay thicknesses of 42-74 ft. Where the sandstone is hydrocarbon bearing, it has a 100% net/ gross ratio. Porosities average 28% and permeabilities lie in the range 0-1 to 1.3 darcies. Wireline and test data indicate that the field contains a continouous oil column of 200 ft. Three distinct structural culminations exist on and adjacent to the field, which give rise to three separate gas caps, centred around wells 2/10a-4, 2/10a-7 and 2/10a-6 The maximum flow rate achieved from the reservoir to date is 6822 BOPD of 24° API oil with a GOR of 300 SCF/STBBL. In-place hydrocarbons are estimated to be 216 MMBBL of oil and 61 BCF of gas, with an estimated 43 MMBBL of oil recoverable by the initial development plan. initial development drilling began in Spring 1989 and the development scheme will use a floating production system. Production to the facility, via flexible risers, is from seven pre-drilled deviated wells with gas lift. An additional four pre-drilled water injection wells will provide reservoir pressure support.

scholarly journals Bayesian calibration of a natural state geothermal reservoir model, Krafla, north Iceland

2021 ◽  
Author(s):  
Samuel Scott ◽  
John P O'Sullivan ◽  
Oliver J Maclaren ◽  
Ruanui Nicholson ◽  
Cari Covell ◽  
...  
Keyword(s):  
Geothermal Reservoir ◽  
Natural State ◽  
Reservoir Model ◽  
Bayesian Calibration

scholarly journals Natural State Modeling of Singapore Geothermal Reservoir

2012 ◽  
Vol 3 ◽  
pp. 34-40
Author(s):  
Hendrik Tjiawi ◽  
Andrew C. Palmer ◽  
Grahame J. H. Oliver
Keyword(s):  
Hot Springs ◽  
Hot Spring ◽  
High Heat ◽  
Hot Water ◽  
Geothermal Reservoir ◽  
Natural State ◽  
Geothermal System ◽  
Fuel Price ◽  
The Cost ◽  
Engineered Geothermal System

 The existence of hot springs coupled with the apparent anomalous high heat flow has sparked interest in the potential for geothermal development in Singapore. This geothermal resource may be potentially significant and could be exploited through Engineered Geothermal System (EGS) technology, i.e. a method to create artificial permeability at depth in granitic or sandstone formations as found under Singapore. The apparently ever-increasing fossil fuel price has made the cost of using the EGS technology more viable than it was in the past. Thus, to assess the resource, a numerical model for the geothermal reservoir has been constructed. Mass and heat flows in the system are simulated in 2D with AUTOUGH2.2, and the graphical interface processed through MULGRAPH2.2. Natural state calibration was performed to match both the observed and the expected groundwater profile, and also to match the hot water upflow at the Sembawang hot spring, with simulated flowrate matching the hot spring natural flowrate. The simulation gives an encouraging result of 125 - 150 °C hot water at depth 1.25 – 2.75 km.

New method of controlling excessive water production in wells using induced formation damage

2015 ◽  
Vol 55 (2) ◽  
pp. 485
Author(s):  
Abbas Zeinijahromi ◽  
Pavel Bedrikovetski
Keyword(s):  
Fresh Water ◽  
Large Scale ◽  
Produced Water ◽  
Water Injection ◽  
Cost Effective ◽  
Formation Damage ◽  
Water Production ◽  
Permeable Barrier ◽  
Water Influx ◽  
Excessive Water

Excessive water production is a major factor in reduced well productivity. This can result from water channelling from the water table to the well through natural fractures or faults, water breakthrough in high permeability zones, or water coning. The use of foams or gels for controlling water production through high-permeable layers has been tested successfully in several field cases. A large treatment volume, however, is required to block the water influx that generally involves high operational and material costs. This extended abstract proposes a new cost-effective method of creating a low-permeable barrier against the produced water with induced formation damage. The method includes applying induced formation damage to block the water influx without hindering the oil production. This can be achieved by injection of a small slug of fresh water into the water-producing layer. This results in release of in situ fines from the matrix, which can decrease permeability and create a local low-permeable barrier to the producing water. In large-scale approximation, water injection with induced fines migration is analogous to polymer flooding. This analogy is used to model the fresh water with induced formation damage. Sensitivity studies showed that the injection of 0.01 PVI of fresh water resulted in the blockage of the water-producing layer and an incremental recovery by 8% in field case A, with respect to the standard production scenario. The authors found that the incremental gas recovery with induced formation damage was sensitive to reservoir heterogeneity, permeability reduction and slug volume.

A New Methodology of Production Performance Prediction for Strong Edge-Water Reservoir

2020 ◽  
Vol 143 (8) ◽  
Author(s):  
Angang Zhang ◽  
Zifei Fan ◽  
Lun Zhao ◽  
Jincai Wang ◽  
Heng Song
Keyword(s):  
Performance Prediction ◽  
Water Saturation ◽  
Water Injection ◽  
Material Balance ◽  
Water Reservoir ◽  
Production Performance ◽  
Water Flooding ◽  
Gas Oil ◽  
Permeability Model ◽  
Water Influx

Abstract Material balance is a basic principle in reservoir engineering, which is still used as a quick and easy analytical tool for reservoir evaluation. In this article, a new methodology of production performance prediction for water-flooding reservoir was proposed based on the material balance principle, which considers the water saturation change caused by water injection and natural water influx, and its effect on transient gas–oil ratio. Among them, the cumulative water production was calculated based on Tong’s water-driver performance curve; the cumulative water influx was obtained by the Fetkovitch method; the transient gas–oil ratio can be acquired by Darcy’s law and Baker’s relative permeability model. Comparisons have been made between the new methodology and commercial reservoir simulator for two different reservoirs. The results show that there is good similarity between these two tools, which verifies the correctness of the new methodology.

Sign in / Sign up

Export Citation Format

Share Document