Successful Development and Deployment of a Novel Chemical Package for Stimulation of Injection wells, Offshore UK

2021 ◽  
Author(s):  
Dennis Alexis ◽  
Gayani Pinnawala ◽  
Do Hoon Kim ◽  
Varadarajan Dwarakanath ◽  
Ruth Hahn ◽  
...  
Keyword(s):  
Product Quality ◽  
Injection Well ◽  
Concentrated Solutions ◽  
Successful Development ◽  
Injection Wells ◽  
Polymer Injection ◽  
Remediation Process ◽  
Field Location ◽  
Stimulation Of ◽  
Injection Rates

Abstract The work described in this paper details the development of a single stimulation package that was successfully used for treating an offshore horizontal polymer injection well to improve near wellbore injectivity in the Captain field, offshore UK. The practice was to pump these concentrated surfactant streams using multiple pumps from a stimulation vessel which is diluted with the polymer injection stream in the platform to be injected downhole. The operational challenges were maintaining steady injection rates of the different liquid streams which was exacerbated by the viscous nature of the concentrated surfactants that would require pre-dilution using cosolvent or heating the concentrated solutions before pumping to make them flowable. We have developed a single, concentrated liquid blend of surfactant, polymer and cosolvent that was used in near-wellbore remediation. This approach significantly simplifies the chemical remediation process in the field while also ensuring consistent product quality and efficiency. The developed single package is multiphase, multicomponent in nature that can be readily pumped. This blend was formulated based on the previous stimulation experience where concentrated surfactant packages were confirmed to work. Commercial blending of the single package was carried out based on lab scale to yard scale blending and dilution studies. About 420 MT of the blend was manufactured, stored, and transported by rail, road and offshore stimulation vessel to the field location and successfully injected.

scholarly journals Capillary processes increase salt precipitation during CO2 injection in saline formations

2018 ◽  
Vol 852 ◽  
pp. 398-421
Author(s):  
Helena L. Kelly ◽  
Simon A. Mathias
Keyword(s):  
High Salinity ◽  
Volume Fraction ◽  
Injection Rate ◽  
Injection Well ◽  
Co2 Injection ◽  
Salt Precipitation ◽  
Injection Wells ◽  
Tenfold Increase ◽  
Entry Pressure ◽  
Injection Rates

An important attraction of saline formations for CO2 storage is that their high salinity renders their associated brine unlikely to be identified as a potential water resource in the future. However, high salinity can lead to dissolved salt precipitating around injection wells, resulting in loss of injectivity and well deterioration. Earlier numerical simulations have revealed that salt precipitation becomes more problematic at lower injection rates. This article presents a new similarity solution, which is used to study the relationship between capillary pressure and salt precipitation around CO2 injection wells in saline formations. Mathematical analysis reveals that the process is strongly controlled by a dimensionless capillary number, which represents the ratio of the CO2 injection rate to the product of the CO2 mobility and air-entry pressure of the porous medium. Low injection rates lead to low capillary numbers, which in turn are found to lead to large volume fractions of precipitated salt around the injection well. For one example studied, reducing the CO2 injection rate by 94 % led to a tenfold increase in the volume fraction of precipitated salt around the injection well.

The Technology Limits for Stratified Injection of Polymer Flooding

2015 ◽  
Vol 1094 ◽  
pp. 433-436
Author(s):  
Qi Sun ◽  
Jing Yang ◽  
Li Yan Sun ◽  
Xiu Long Dong
Keyword(s):  
Class Ii ◽  
Scientific Basis ◽  
Polymer Flooding ◽  
Injection Well ◽  
Injection Wells ◽  
Development Zone ◽  
Polymer Injection ◽  
Geological Conditions ◽  
Injection Technology ◽  
Separate Injection

At present the development of Daqing Oilfield has entered the water pick-up period, and the polymer separate injection technology for the injection well is urgent needed. However, the difficulty of selecting well and lever for the separate injection of the injection well is relatively large due to the complexity of the Class II reservoir of geological conditions. So for The limits of technology of the geological features, the limits of technology injection of stratified polymer injection for the Class II reservoir provides a scientific basis for the development of oil fields.In this paper, taking Daqing Oilfield Sabei Development Zone as example, establish the mathematical model of polymer flooding. Determine the well and layer selection principles of layered polymer injection wells in the ClassIIreservoir timing. According to the current development situation, give the decrease in water content and the improvement value in recovery under a given measure.Through this paper, we have got production effect of layered polymer injection in the Class II reservoir of Sabei area and given quantified layered polymer injection technology limits.

Monitoring Polymer Flooding Performance Using Inflow Tracer Technology in Horizontal Injection and Production Wells

2021 ◽  
pp. 1-18
Author(s):  
Alyssia Janczak ◽  
Gaute Oftedal ◽  
Ehsan Nikjoo ◽  
Michaela Hoy ◽  
Christoph Puls ◽  
...  
Keyword(s):  
Horizontal Well ◽  
Produced Water ◽  
Spatial Information ◽  
Numerical Models ◽  
Horizontal Wells ◽  
Injection Well ◽  
Efficient Production ◽  
Injection Wells ◽  
Polymer Injection ◽  
Production Wells

Summary Horizontal wells are frequently used to increase injectivity and for cost-efficient production of mobilized oil in polymer-augmented waterfloods. Usually, only fluid and polymer production data at the wellhead of the production well are available. We used inflow tracer technology to determine changes in hydrocarbon influx owing to polymer injection and to determine the connection from various zones of the horizontal injector to the horizontal producer. Inflow tracer technology was introduced in horizontal polymer injection and production wells. In the production wells, tracers are released when they are contacted by water and oil. Oil and water tracer systems were used in the horizontal production wells. The changes in the observed tracer concentration were used to quantify changes in influx from various sections of the horizontal producers owing to polymer injection. The inflow tracer technology applied in the horizontal injection wells demonstrates connectivity between different sections of the injection wells and two surrounding vertical and horizontal production wells and opens the usage of this technology for interwell water tracer applications. Inflow tracer technology enables one to elucidate the inflow from various sections of the horizontal wells and the changes thereof, even quantifying changes in influx of various fluids (oil and water). The information shows which sections are contributing and the substantial changes in the influx of oil from the various zones due to polymer solution injection. The overall incremental oil could be allocated to the various horizontal well sections based on the tracer results. Even zones that almost exclusively produced water before polymer injection showed a significant increase in oil influx. The inflow tracer technology installed in the injection well allowed us to analyze the connectivity of the injector to producer not only globally but spatially along the horizontal well. These data are used for reservoir characterization, to condition numerical models, and for reservoir management. Conventional interwell tracer technology allows one to determine the connectivity and connected volumes of horizontal well polymer field developments. However, it reveals neither information about influx of the sections nor the connectivity of various sections of the horizontal wells. Inflow tracer technology closes this gap; it allows one to quantify changes in influx of the fluids. Furthermore, the newly developed installed injection well tracer technology gives spatial information about the connectivity of the horizontal well sections.

CALCULATION OF OPTIMAL INJECTION RATE FOR DISPERSED WATERFLOODING SYSTEM

2017 ◽  
pp. 63-67
Author(s):  
L. A. Vaganov ◽  
A. Yu. Sencov ◽  
A. A. Ankudinov ◽  
N. S. Polyakova
Keyword(s):  
Injection Rate ◽  
Oil Field ◽  
Injection Well ◽  
Water Migration ◽  
Mutual Location ◽  
Optimal Injection ◽  
Technical Measures ◽  
Injection Rates

The article presents a description of the settlement method of necessary injection rates calculation, which is depended on the injected water migration into the surrounding wells and their mutual location. On the basis of the settlement method the targeted program of geological and technical measures for regulating the work of the injection well stock was created and implemented by the example of the BV7 formation of the Uzhno-Vyintoiskoe oil field.

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.

Field Demonstration of the Impact of Fractures on Hydrolyzed Polyacrylamide Injectivity, Propagation, and Degradation

SPE Journal ◽  
2022 ◽  
pp. 1-18
Author(s):  
Marat Sagyndikov ◽  
Randall Seright ◽  
Sarkyt Kudaibergenov ◽  
Evgeni Ogay
Keyword(s):  
Polymer Solutions ◽  
Mechanical Stability ◽  
Field Operator ◽  
Oil Field ◽  
Low Flow ◽  
Mechanical Degradation ◽  
Injection Wells ◽  
Polymer Injection ◽  
Step Rate ◽  
The Impact

Summary During a polymer flood, the field operator must be convinced that the large chemical investment is not compromised during polymer injection. Furthermore, injectivity associated with the viscous polymer solutions must not be reduced to where fluid throughput in the reservoir and oil production rates become uneconomic. Fractures with limited length and proper orientation have been theoretically argued to dramatically increase polymer injectivity and eliminate polymer mechanical degradation. This paper confirms these predictions through a combination of calculations, laboratory measurements, and field observations (including step-rate tests, pressure transient analysis, and analysis of fluid samples flowed back from injection wells and produced from offset production wells) associated with the Kalamkas oil field in Western Kazakhstan. A novel method was developed to collect samples of fluids that were back-produced from injection wells using the natural energy of a reservoir at the wellhead. This method included a special procedure and surface-equipment scheme to protect samples from oxidative degradation. Rheological measurements of back-produced polymer solutions revealed no polymer mechanical degradation for conditions at the Kalamkas oil field. An injection well pressure falloff test and a step-rate test confirmed that polymer injection occurred above the formation parting pressure. The open fracture area was high enough to ensure low flow velocity for the polymer solution (and consequently, the mechanical stability of the polymer). Compared to other laboratory and field procedures, this new method is quick, simple, cheap, and reliable. Tests also confirmed that contact with the formation rapidly depleted dissolved oxygen from the fluids—thereby promoting polymer chemical stability.

scholarly journals Characterizing microseismicity at the Rotokawa and Ngatamariki geothermal fields

2021 ◽  
Author(s):  
◽  
Chet Hopp
Keyword(s):  
Matched Filter ◽  
Fluid Pressure ◽  
B Value ◽  
Injection Well ◽  
Taupo Volcanic Zone ◽  
Reservoir Properties ◽  
Injection Wells ◽  
Small Magnitude ◽  
Magnitude Distribution ◽  
Geothermal Fields

<p>In this thesis, we construct a four-year (2012–2015) catalog of microearthquakes for the Ngatamariki and Rotokawa geothermal fields in the Taupō Volcanic Zone of New Zealand, and use these data to improve the knowledge of reservoir behavior. These microearthquakes occur frequently, often every few seconds, and therefore provide a tool that we use to assess reservoir properties with dense spatial and temporal resolution as well as to illuminate the underlying processes of seismogenesis. Using a matched-filter detection technique we detect and precisely relocate nearly 9000 events, from which we calculate 982 focal mechanisms.  At Ngatamariki, these results constitute the first detailed analysis of seismicity at a newly-developed resource. It has been commonly assumed that induced shear on fractures increases reservoir permeability by offsetting asperities on either fracture wall, thereby propping the fracture open. During stimulation treatments of two boreholes (NM08 and NM09), borehole permeability experiences logarithmic growth. At NM08, this growth occurs for eight days in the absence of seismicity, while at NM09 only nine microearthquakes are observed during the one-month treatment. This suggests that hydro-shear, the process of inducing seismicity through increased pore pressure at critically-stressed fractures, is not the dominant mechanism of permeability increase at many geothermal wells. Instead, aseismic processes, likely thermal and overpressure induced fracture opening, dominate well stimulation in high-temperature geothermal settings.  At Rotokawa, the earthquake frequency-magnitude distribution (b-value) is positively correlated with both proximity to major injection wells and depth. In an inferred pressure compartment near injection well RK23, b is ~1.18, but is <1.0 elsewhere, suggesting a connection between increased pore-fluid pressure and small-magnitude events. In addition, throughout the reservoir b increases from a value of ~1.0 at injection depth to almost 1.5 two kilometers below the reservoir, consistent with observations at volcanic areas elsewhere, but opposing the conventional wisdom that b-value is inversely proportional to differential stress.  Finally, the 982 focal mechanism observations that we invert for stress show a normal faulting regime throughout both reservoirs. At Rotokawa, a lowering stress ratio, v, after reintroduction of injection well RK23 (v drops from 0.9 to 0.2 over six months) indicates that anisotropic reservoir cooling affects the reservoir stress state through a process of preferential stress reduction.</p>

Surfactant-Enhanced Stimulation Technology for Polymer-Injection Wells

2005 ◽  
Author(s):  
Yan Wang ◽  
Demin Wang ◽  
Zhi Sun ◽  
Song Zhao ◽  
Gang Wang ◽  
...  
Keyword(s):  
Injection Wells ◽  
Polymer Injection
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