scholarly journals Dynamics of clogging processes in injection wells used to pump highly mineralized thermal waters into the sandstone structures lying under the polish lowlands

2012 ◽  
Vol 38 (3) ◽  
pp. 105-117 ◽  
Author(s):  
Barbara Tomaszewska ◽  
Leszek Pająk
Keyword(s):  
Water Injection ◽  
Real Life ◽  
Injection Pressure ◽  
Operating Conditions ◽  
Solid Particles ◽  
Injection Well ◽  
Thermal Waters ◽  
Geothermal Systems ◽  
Injection Wells ◽  
Geothermal Resources

Abstract When identifying the conditions required for the sustainable and long-term exploitation of geothermal resources it is very important to assess the dynamics of processes linked to the formation, migration and deposition of particles in geothermal systems. Such particles often cause clogging and damage to the boreholes and source reservoirs. Solid particles: products of corrosion processes, secondary precipitation from geothermal water or particles from the rock formations holding the source reservoir, may settle in the surface installations and lead to clogging of the injection wells. The paper proposes a mathematical model for changes in the absorbance index and the water injection pressure required over time. This was determined from the operating conditions for a model system consisting of a doublet of geothermal wells (extraction and injection well) and using the water occurring in Liassic sandstone structures in the Polish Lowland. Calculations were based on real data and conditions found in the Skierniewice GT-2 source reservoir intake. The main product of secondary mineral precipitation is calcium carbonate in the form of aragonite and calcite. It has been demonstrated that clogging of the active zone causes a particularly high surge in injection pressure during the fi rst 24 hours of pumping. In subsequent hours, pressure increases are close to linear and gradually grow to a level of ~2.2 MPa after 120 hours. The absorbance index decreases at a particularly fast rate during the fi rst six hours (Figure 4). Over the period of time analysed, its value decreases from over 42 to approximately 18 m3/h/MPa after 120 hours from initiation of the injection. These estimated results have been confi rmed in practice by real-life investigation of an injection well. The absorbance index recorded during the hydrodynamic tests decreased to approximately 20 m3/h/MPa after 120 hours.

A New Method of Fall-Off Test in Water Injection Well in Tahe Oilfield

2013 ◽  
Vol 807-809 ◽  
pp. 2508-2513
Author(s):  
Qiang Wang ◽  
Wan Long Huang ◽  
Hai Min Xu
Keyword(s):  
Water Injection ◽  
Injection Well ◽  
Well Test ◽  
Well Bore ◽  
Residual Oil ◽  
Injection Wells ◽  
Oil Saturation ◽  
Tahe Oilfield ◽  
Fitting Method ◽  
Front Radius

In pressure drop well test of the clasolite water injection well of Tahe oilfield, through nonlinear automatic fitting method in the multi-complex reservoir mode for water injection wells, we got layer permeability, skin factor, well bore storage coefficient and flood front radius, and then we calculated the residual oil saturation distribution. Through the examples of the four wells of Tahe oilfield analyzed by our software, we found that the method is one of the most powerful analysis tools.

The New Generation of Outflow Control Devices Autonomously Controlling the Conformance of Water Injection Well- A Case Study with ADNOC Onshore

2021 ◽  
Author(s):  
Sultan Ibrahim Al Shemaili ◽  
Ahmed Mohamed Fawzy ◽  
Elamari Assreti ◽  
Mohamed El Maghraby ◽  
Mojtaba Moradi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Dynamic Properties ◽  
Short Circuit ◽  
Water Injection ◽  
Performance Outcomes ◽  
Injection Well ◽  
Well Performance ◽  
Injection Wells ◽  
Horizontal Section ◽  
Control Devices

Abstract Several techniques have been applied to improve the water conformance of injection wells to eventually improve field oil recovery. Standalone Passive flow control devices or these devices combined with Sliding sleeves have been successful to improve the conformance in the wells, however, they may fail to provide the required performance in the reservoirs with complex/dynamic properties including propagating/dilating fractures or faults and may also require intervention. This is mainly because the continuously increasing contrast in the injectivity of a section with the feature compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone which ultimately creates short-circuit to the nearby producer wells. The new autonomous injection device overcomes this issue by selectively choking the injection of fluid into the growing fractures crossing the well. Once a predefined upper flowrate limit is reached at the zone, the valves autonomously close. Well A has been injecting water into reservoir B for several years. It has been recognised from the surveys that the well passes through two major faults and the other two features/fractures with huge uncertainty around their properties. The use of the autonomous valve was considered the best solution to control the water conformance in this well. The device initially operates as a normal passive outflow control valve, and if the injected flowrate flowing through the valve exceeds a designed limit, the device will automatically shut off. This provides the advantage of controlling the faults and fractures in case they were highly conductive as compared to other sections of the well and also once these zones are closed, the device enables the fluid to be distributed to other sections of the well, thereby improving the overall injection conformance. A comprehensive study was performed to change the existing dual completion to a single completion and determine the optimum completion design for delivering the targeted rate for the well while taking into account the huge uncertainty around the faults and features properties. The retrofitted completion including 9 joints with Autonomous valves and 5 joints with Bypass ICD valves were installed in the horizontal section of the well in six compartments separated with five swell packers. The completion was installed in mid-2020 and the well has been on the injection since September 2020. The well performance outcomes show that new completion has successfully delivered the target rate. Also, the data from a PLT survey performed in Feb 2021 shows that the valves have successfully minimised the outflow toward the faults and fractures. This allows achieving the optimised well performance autonomously as the impacts of thief zones on the injected fluid conformance is mitigated and a balanced-prescribed injection distribution is maintained. This paper presents the results from one of the early installations of the valves in a water injection well in the Middle East for ADNOC onshore. The paper discusses the applied completion design workflow as well as some field performance and PLT data.

Research of Improving Water Injection Effect by Using Active SiO2 Nano-Powder in the Low-Permeability Oilfield

2010 ◽  
Vol 92 ◽  
pp. 207-212 ◽  
Author(s):  
Ke Liang Wang ◽  
Shou Cheng Liang ◽  
Cui Cui Wang
Keyword(s):  
Oil Recovery ◽  
Pore Volume ◽  
Water Injection ◽  
Field Tests ◽  
Injection Pressure ◽  
Rock Surface ◽  
Low Permeability ◽  
Injection Wells ◽  
Decompression Rate ◽  
Nano Powder

SiO2 nano-powder is a new type of augmented injection agent, has the ability of stronger hydrophobicity and lipophilicity, and can be adsorbed on the rock surface so that it changes the rock wettability. It can expand the pore radius effectively, reduce the flow resistance of injected water in the pores, enhance water permeability, reduce injection pressure and augment injection rate. Using artificial cores which simulated geologic conditions of a certain factory of Daqing oilfield, decompression and augmented injection experiments of SiO2 nano-powder were performed after waterflooding, best injection volume of SiO2 nano-powder under the low-permeability condition was selected. It has shown that SiO2 nano-powder inverted the rock wettability from hydrophilicity to hydrophobicity. Oil recovery was further enhanced after waterflooding. With the injection pore volume increasing, the recovery and decompression rate of SiO2 nano-powder displacement increased gradually. The best injected pore volume and injection concentration is respectively 0.6PV and 0.5%, the corresponding value of EOR is 6.84% and decompression rate is 52.78%. According to the field tests, it is shown that, in the low-permeability oilfield, the augmented injection technology of SiO2 nano-powder could enhance water injectivity of injection wells and reduce injection pressure. Consequently, it is an effective method to resolve injection problems for the low-permeability oilfield.

Fault Sealing Property Analyzing by Water Injection in Oilfields

2013 ◽  
Vol 295-298 ◽  
pp. 3205-3208 ◽  
Author(s):  
Peng Fei Shen ◽  
Ling Li ◽  
Yong Sheng Chen ◽  
Nian Qiao Fang ◽  
Jian Li ◽  
...  
Keyword(s):  
Water Injection ◽  
Injection Well ◽  
Injection Wells ◽  
Availability Analysis ◽  
Fault Block ◽  
Sealing Ability ◽  
Small Fault ◽  
General Method

The quantity and availability of water injection are affected by geological environments in complex small fault-block oilfields, especially nearby faults. It is a general method to qualitatively determine fault sealing ability by water injection availability. The availability analysis of several injection wells can judge sealing ability of five faults of block M28-1 in JD oilfield. The water injection data show that fault F1, F4, F5 are main areas of pressure releasing for unsealing. Fault F2 and F3 are distributed on each side of the water injection well, which have a little influence on loss of water injection for sealing.

Horizontal Water Injection Wells: Injectivity and Containment of Injection-Induced Fractures

2021 ◽  
Author(s):  
Jongsoo Hwang ◽  
Mukul Sharma ◽  
Maria-Magdalena Chiotoroiu ◽  
Torsten Clemens
Keyword(s):  
Horizontal Well ◽  
Water Injection ◽  
Fracture Initiation ◽  
Horizontal Stress ◽  
Operating Conditions ◽  
Critical Factors ◽  
Injection Wells ◽  
Stress Direction ◽  
Maximum Horizontal Stress ◽  
Transverse Fractures

Abstract Horizontal water injection wells have the capacity to inject larger volumes of water and have a smaller surface footprint than vertical wells. We present a new quantitative analysis on horizontal well injectivity, injection scheme (matrix vs. fracturing), and fracture containment. To precisely predict injector performance and delineate safe operating conditions, we simulate particle plugging, thermo-poro-elastic stress changes, thermal convection and conduction and fracture growth/containment in reservoirs with multiple layers. Simulation results show that matrix injection in horizontal wells continues over a longer time than vertical injectors as the particle deposition occurs slowly on the larger surface area of horizontal wellbores. At the same time, heat loss occurs uniformly over a longer wellbore length to cause less thermal stress reduction and delay fracture initiation. As a result, the horizontal well length and the injection rates are critical factors that control fracture initiation and long-term injectivity of horizontal injectors. To predict fracture containment accurately, thermal conduction in the caprock and associated thermal stresses are found to be critical factors. We show that ignoring these factors underestimates fracture height growth. Based on our simulation analysis, we suggest strategies to maintain high injectivity and delay fracture initiation by controlling the injection rate, temperature, and water quality. We also provide several methods to design horizontal water injectors to improve fracture containment considering wellbore orientation relative to the local stress orientations. Well placement in the local maximum horizontal stress direction induces longitudinal fractures with better containment and less fracture turning than transverse fractures. When the well is drilled perpendicular to the maximum horizontal stress direction, the initiation of transverse fractures is delayed compared with the longitudinal case. Flow control devices are recommended to segment the flow rate and the wellbore. This helps to ensure uniform water placement and helps to keep the fractures contained.

Assessment of Injection Pressure Margin in Deep Water Injection Well Design

2015 ◽  
Author(s):  
Becky B. Poon ◽  
Ebimobowei K. Wodu ◽  
Abraham O. Ekebafe ◽  
Edgar Mba Ognane ◽  
Osazua J. Itua ◽  
...  
Keyword(s):  
Deep Water ◽  
Water Injection ◽  
Injection Pressure ◽  
Injection Well ◽  
Well Design

scholarly journals The Relationship Analysis between Water Injection and Microfacies of SHA1 Reservoir of Liao He Basin, China

2014 ◽  
Vol 2014 ◽  
pp. 1-5
Author(s):  
Qing Wang ◽  
Zhanguo Lu ◽  
Shiguang Guo ◽  
Chao Wang
Keyword(s):  
Water Injection ◽  
Injection Pressure ◽  
Leading Edge ◽  
Inversion Method ◽  
Injection Wells ◽  
Relationship Analysis ◽  
Before And After ◽  
Mouth Bar ◽  
The Relationship ◽  
Distributary Channel

SHA1 is the representative reservoir in Liao He Basin. Through the introduction of curvature displayed on the gray scale, we determine the substructure and fractures. Geostatistical inversion method is used to help study the porosity of reservoir. The relationship between interval transit times and resistivity among mudstone and sandstone, before and after water injection, is analyzed. The relationship between porosity and permeability and the relationship between porosity and impedance from core analysis were studied. Through the whole information above, we divide the microfacies of SHA1 reservoir to distributary channel, mouth bar, the leading edge thin sand, and prodelta mud. The water injections in different microfacies are studied. The distributary channel should be used by large distant injection wells or smaller injection pressure injection. The smaller distant injection wells or large injection pressure should be used in the mouth bar. The arrangement of well injection need consider the different sedimentary microfacies.

Unified Fracturing Design for Water Injection Well under Steady State Flow Regime

2013 ◽  
Vol 295-298 ◽  
pp. 3175-3182
Author(s):  
Dan Luo ◽  
Zhao Zhong Yang ◽  
Xiao Gang Li ◽  
Zhou Su
Keyword(s):  
Steady State ◽  
Flow Regime ◽  
Water Injection ◽  
Optimization Method ◽  
Injection Well ◽  
Steady State Flow ◽  
Injection Wells ◽  
Fracture Geometry ◽  
Type Curves ◽  
State Flow

Unified Fracture Design for fracturing optimization is a simple and reliable way to push the limit of the injection ability, reported frequently in recent years. However, most studies focus on fracture design under pseudo-steady state flow regime. The analysis of the different pressure systems between water injection well and oil production well tells us that the steady flow regime in the formation takes up most life span of water injection wells, associated with the field experience. To maximize injection capability for fractured vertical water wells under this regime, a physical optimization method is developed based on the concept of proppant number. Meanwhile, two new type curves without consideration of formation damage are obtained for quantifying the correlation between dimensionless injectivity and dimensionless conductivity. Then, calibrated design procedures accounting for gel damage and non-darcy effect, are also proposed. Finally, sensitivity studies are addressed to clarify the effect of several variables on the optimum fracture geometry.

Research on Degradation of Flocculating Stemming Contained Polymer and Clay Used for Profile Control

2014 ◽  
Vol 912-914 ◽  
pp. 297-300
Author(s):  
Wei Zhang ◽  
Shuang Yan Zhang ◽  
Deng Feng Ju ◽  
Hai Jun Yan ◽  
Guo Qing Fu ◽  
...  
Keyword(s):  
Yellow River ◽  
Sol Gel ◽  
Water Injection ◽  
Injection Pressure ◽  
Control Agent ◽  
Oil Wells ◽  
Control Technique ◽  
Injection Wells ◽  
Fracture Pressure ◽  
Profile Control

Since Menggulin reservoir fully been developed in1990, profile control technique is widely used for improving water swept volume. After multiple rounds and large-scales of polymer flooding by materials mixed with sol-gel and Yellow River clay, the formation damage such as depth blockage and stemming become more and more serious.According to statistics, in 2012 there are respectively 10 and 11 water injection wells happened with back flow of profile control agent and wells pressure higher than fracture pressure that without injection. The original reservoir permeability is good, and individual well production has the capacity of 40 to 50m3/d. Yet recently several oil wells almost have fewer even no liquid output due to the blockage and stemming. Estimated by a typical well group,the speed of sol-gel drive increased from 10 m/year to 50~60 m/year, and average water injection pressure were up to 16MPa which almost double original pressure while the only 2MPa pressure corresponding to oil wells. Hence, it show that the severe depth blockage of the formation exactly exit in Menggulin reservoir.

Study of Enhancing Water Adsorbing Index by Nanometer-Sized Silicon Oxide in Water Injection Well

2007 ◽  
Vol 121-123 ◽  
pp. 1497-1500 ◽  
Author(s):  
Hai Wen Wang
Keyword(s):  
Flow Resistance ◽  
Silicon Oxide ◽  
Water Injection ◽  
Injection Pressure ◽  
Paper Analysis ◽  
Injection Well ◽  
Water Flooding ◽  
Low Permeability ◽  
Oil Reservoir ◽  
Phase Permeability

Nanometer-sized silicon oxide can be used in water flooding in oil development because of its super hydrophobic and oleophilic ability. In oil reservoir, these nanomaterials are usually physically adsorbed on the surface of sandstone and improve the wettability and water phase permeability. Therefore flow resistance is reduced and water adsorbing index is increased. Both experiment and application results show that nanometer silicon oxide is an excellent material used for water flooding, water injection pressure and ability of adsorping water in low permeability reservoir. The paper analysis the mechanism of increasing water adsorbing index and discuss the conditions for selecting water injection well.

Sign in / Sign up

Export Citation Format

Share Document