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.

Autonomous Outflow Control Technology AOCD in New Water/Polymer Injectors in Heavy Oil Fields from South Sultanate of Oman

2021 ◽  
Author(s):  
Ameera Al Harrasi ◽  
Muna Maskari ◽  
Gerardo Urdaneta ◽  
Ali Al-Jumah ◽  
Salim Badi ◽  
...  
Keyword(s):  
Oil Recovery ◽  
Dynamic Properties ◽  
Short Circuit ◽  
Oil Fields ◽  
Water Flooding ◽  
Reactive Control ◽  
Static Properties ◽  
Injection Wells ◽  
Control Devices ◽  
Great Portion

Abstract Several techniques have been applied to improve fluid conformance of injection wells to increase water flooding performance and eventually field oil recovery. Normal outflow control devices (OCDs) are effective solutions for this problem in reservoirs with static properties, however, they fail in reservoirs with complex/dynamic properties including fractures. There, the continuously increasing contrast in the injectivity of a section with the fractures compared to the rest of the well causes diverting a great portion of the injected fluid into the thief zone thus creating short-circuit to the nearby producer wells. This paper summarizes the integrated technical learnings from the successful application of the installation of the first Autonomous Outflow Control (AOCD) technology in a new long horizontal injector well. It shows the result of extending this technology to other injectors in both water and polymer phases in the field, it details the facts and observations and the insights the multidisciplinary authors have captured. This autonomously reactive control on the injection fluid conformance resulted in an increased sweep and ultimate oil recovery while reducing the total volume of injected fluid.

Autonomously Controlling the Conformance of Injection-Well Fluids

2021 ◽  
Vol 73 (06) ◽  
pp. 38-40
Author(s):  
Mojtaba Moradi
Keyword(s):  
Flow Control ◽  
Oil Recovery ◽  
Water Injection ◽  
Injection Well ◽  
Reservoir Pressure ◽  
Injection Wells ◽  
Control Valves ◽  
Sand Control ◽  
Control Devices ◽  
Fracture Growth

As production declines over time, the injection of fluids is required to enhance oil recovery and/or maintain the reservoir pressure. Whether applied at field startup or as a secondary recovery technique, waterflooding can boost oil recovery from less than 30% to 30–50%. The common problems associated with waterflooding include loss of injectivity, premature injector failure, and injection conformance. This can also lead to issues around insufficient voidage replacement, which can result in lower reservoir pressure and the production of fluid with a higher gas/oil ratio. In total field recovery, this ultimately means lower production and oil left untapped in the well. To remediate the issue of conformance, costly and often complex interventions and redrills were traditionally used to restore water-injection capability. Also, passive outflow-control devices have been used successfully to somewhat improve the fluid conformance from injection wells. However, they may fail in reservoirs with complex/dynamic properties including propagating/dilating fractures. Advanced Wells in Injection Wells There are a number of considerations when planning a water-injection completion, particularly around both the rock and fluid properties, as well as the credible risks that could occur, namely: - Uneven displacement of hydrocarbon - Fracture growth short-circuiting injectant-proximal wells - Fracture growth breaching caprock/basement seal - Crossflow, plugging, and solids fill Advanced completion options include deploying passive flow-control devices. For example, inflow-control devices (ICDs) are unable to react to dynamic changes in reservoir/well properties. This often requires production-logging-tool (PLT) logs, distributed temperature sensors, and/or tracers to be run and, if available, to apply the sleeve option. Alternatively, active (intelligent) completions, such as inflow-control valves, can be used, but they tend to be expensive and complicated and are limited to the number of zones. This technique also requires frequent analysis of data from the well to perform such actions. Tendeka, a global specialist in advanced completions, production solutions, and sand control, has developed FloFuse, a new and exclusively autonomous rate-limiting outflow-control device (AOCD) (Fig. 1). Using the analogy and inspiration of a home fuse box, which contains many individual fuses to control various parts of a building, the AOCD can control the excessive rate that passes through a specific section of a well, causing tripping once the threshold is reached. By almost shutting, i.e., significantly choking, the injection fluid into the fractures crossing the well, the AOCD autonomously prevents growth and excessive fluid injection into the thief/fracture zones and maintains a balanced or prescribed injection distribution. Like other flow-control valves, this device should be installed in several compartments in the injection well. Initially, devices operate as normal passive outflow control, but if the injected flow rate through the valve exceeds a designed limit, the device will automatically shut off. This allows the denied fluid to that specific compartment to be distributed among the neighboring compartments.

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.

scholarly journals Polymer gels for controlling water thief zones in injection wells

2012 ◽  
Vol 5 (1) ◽  
pp. 37-44 ◽  
Author(s):  
Gustavo-Adolfo Maya-Toro ◽  
Rubén-Hernán Castro-García ◽  
Zarith del Pilar Pachón-Contreras. ◽  
Jose-Francisco Zapata-Arango
Keyword(s):  
Oil Recovery ◽  
Water Injection ◽  
Injection Wells ◽  
Recovery Processes ◽  
Injection Water ◽  
Secondary Oil Recovery ◽  
High Concentrations ◽  
Low Efficiency ◽  
Hydrolyzed Polyacrylamide ◽  
Positive Results

Oil recovery by water injection is the most extended technology in the world for additional recovery, however, formation heterogeneity can turn it into highly inefficient and expensive by channeling injected water. This work presents a chemical option that allows controlling the channeling of important amounts of injection water in specific layers, or portions of layers, which is the main explanation for low efficiency in many secondary oil recovery processes. The core of the stages presented here is using partially hydrolyzed polyacrylamide (HPAM) cross linked with a metallic ion (Cr+3), which, at high concentrations in the injection water (5000 – 20000 ppm), generates a rigid gel in the reservoir that forces the injected water to enter into the formation through upswept zones. The use of the stages presented here is a process that involves from experimental evaluation for the specific reservoir to the field monitoring, and going through a strict control during the well intervention, being this last step an innovation for this kind of treatments. This paper presents field cases that show positive results, besides the details of design, application and monitoring.

An Integrated IR4.0 Software Enables Autonomous Casing Crossflow Rate Calculation

2021 ◽  
Author(s):  
Nasser M. Al-Hajri ◽  
Akram R. Barghouti ◽  
Sulaiman T. Ureiga
Keyword(s):  
Industrial Revolution ◽  
Water Injection ◽  
Flow Characteristics ◽  
Injection Rate ◽  
Performance Model ◽  
Injection Well ◽  
Production Model ◽  
Well Performance ◽  
Secondary Formation ◽  
Well Model

Abstract This paper will present an alternative calculation technique to predict wellbore crossflow rate in a water injection well resulting from a casing leak. The method provides a self-governing process for wellbore related calculations inspired by the fourth industrial revolution technologies. In an earlier work, calculations techniques were presented which do not require the conventional use of downhole flowmeter (spinner) to obtain the flow rate. Rather, continuous surface injection data prior to crossflow development and shut-in well are used to estimate the rate. In this alternative methodology, surface injection data post crossflow development are factored in to calculate the rate with the same accuracy. To illustrate the process an example water injector well is used. To quantify the casing leak crossflow rate, the following calculation methodology was applied:Generate a well performance model using pre-crossflow injection data. Normal modeling techniques are applied in this step to obtain an accurate model for the injection well as a baseline case.Generate an imaginary injection well model: An injection well mimicking the flow characteristics and properties of the water injector is envisioned to simulate crossflow at flowing (injecting) conditions. In this step, we simulate an injector that has total depth up to the crossflow location only and not the total depth of the example water well.Generate the performance model for the secondary formation using post crossflow data: The total injection rate measured at surface has two portions: one portion goes into the shallower secondary formation and another goes into the deeper (primary) formation. The modeling inputs from the first two steps will be used here to obtain the rate for the downhole formation at crossflow conditions.Generate an imaginary production well model: The normal model for the water injector will be inversed to obtain a production model instead. The inputs from previous steps will be incorporated in the inverse modeling.Obtaining the crossflow rate at shut-in conditions: Performance curves generated from step 3 & 4 will be plotted together to obtain an intersection that corresponds to the crossflow rate at shut-in conditions. This numerical methodology was analytically derived and the prediction results were verified on syntactic field data with very high accuracy. The application of this model will benefit oil operators by avoiding wireline logging costs and associated safety risks with mechanical intervention.

Water Hammer Effects on Water Injection Well Performance and Longevity

2008 ◽  
Author(s):  
Xiuli Wang ◽  
Knut Arne Hovem ◽  
Daniel Moos ◽  
Youli Quan
Keyword(s):  
Water Injection ◽  
Water Hammer ◽  
Injection Well ◽  
Well Performance

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.

Overview the 5 Years Experience of Intelligent Separate-Layer Injection Technology in B Offshore Oilfield

2021 ◽  
Author(s):  
Yigang Liu ◽  
Zheng Chen ◽  
Xianghai Meng ◽  
Zhixiong Zhang ◽  
Jian Zou ◽  
...  
Keyword(s):  
Short Circuit ◽  
Water Injection ◽  
Operation Time ◽  
Water Flooding ◽  
Internal Diameter ◽  
Injection Wells ◽  
Mode Water ◽  
Separate Layer ◽  
Injection Technology ◽  
Large Flow

Abstract Nowadays intelligent injection is considered as a new frontier for offshore oilfield. In order to improve the water injection indicators such as allocation frequency and qualification rate, intelligent separate-layer injection technology (ISIT) was researched, deployed and optimized in B offshore oilfield from 2015. In the course of 5 years’ project operation, some experience of success or failure was achieved. B offshore oilfield is the largest offshore oilfield in China with 33 water flooding oilfields and more than 800 water injection wells. With the continuous development, the problem of injection management mainly reflected in the contradiction between increasing demand of allocation and limited operation time and space was exposed. Two kinds of ISIT, cable implanted intelligent separate-layer injection technology(CISIT) and wireless intelligent separate-layer injection technology(WISIT), were deployed to solve the above problem. CISIT controlled the distributor downhole by electricity while WISIT controlled the distributor downhole by pressure pulse. By the use of ISIT, downhole nozzle's action, packer testing and downhole data monitoring could be remotely controlled on the ground. During the 5 years’ test, ISIT was optimized from the field breakdown including large flow range flowing test, cable protection project, efficient coding mode, water seepage resistance and so on. With the continuous optimization and quality control improvement, ISIT has overcome many problems, such as downhole short circuit and communication loss, and is becoming more stable and reliable. At present, ISIT can meet the needs of large flow injection(max 800m3/d per layer) and can adapt to the high frequency of acidizing and fracturing in offshore oilfield. The failure rate of ISIT has dropped to nearly 20% in 2020. As of December 2020, ISIT has formed series products for different internal diameter wells and applied in 156 water injection wells in B offshore oilfield. The average allocation frequency has increased from less than one time to 2 times per year. Through the application of ISIT, B offshore oilfield has accumulatively saved more than 2100 days of platform occupation and more than 73 million RMB yuan of allocation cost. The use of ISIT makes B offshore oilfield's injection become more efficient and intelligent. The 5 years’ experience of ISIT applicationin B offshore oilfield has a fairly referential significance for other offshore oilfields.

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.

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