Business Impact of Frequent Time-lapse Observations Around Valhall Water Injection Well

2010 ◽  
Author(s):  
J. van Gestel ◽  
G. Tjetland ◽  
M. J. Parikh ◽  
J. H. Kommedal ◽  
O. I. Barkved
Keyword(s):  
Water Injection ◽  
Time Lapse ◽  
Injection Well ◽  
Business Impact

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.

Time-lapse seismic surveys in the North Sea and their business impact

2000 ◽  
Vol 19 (3) ◽  
pp. 286-293 ◽  
Author(s):  
Klaas Koster ◽  
Pieter Gabriels ◽  
Matthias Hartung ◽  
John Verbeek ◽  
Geurt Deinum ◽  
...  
Keyword(s):  
North Sea ◽  
Time Lapse ◽  
Seismic Surveys ◽  
Business Impact ◽  
The North ◽  
The North Sea

Business impact of time-lapse data in deepwater Niger Delta

2011 ◽  
Vol 30 (6) ◽  
pp. 662-665 ◽  
Author(s):  
T. O. Fehintola ◽  
G. Olatunbosun
Keyword(s):  
Niger Delta ◽  
Time Lapse ◽  
Business Impact

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.

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.

Ten years of time-lapse seismic on Atlantis Field

2021 ◽  
Vol 40 (7) ◽  
pp. 494-501
Author(s):  
Jean-Paul van Gestel
Keyword(s):  
Waveform Inversion ◽  
Water Injection ◽  
Main Tool ◽  
Time Lapse ◽  
Velocity Model ◽  
Lessons Learned ◽  
Ocean Bottom ◽  
Injection Wells ◽  
History Match ◽  
Business Decisions

In 2019, the fourth ocean-bottom-node survey was acquired over Atlantis Field. This survey was quickly processed to provide useful time-lapse (4D) observations two months after the end of the acquisition. The time-lapse observations were immediately valuable in placing wells, refining final drilling target locations, updating well prioritization, and sequencing production and water-injection wells. These data are indispensable pieces of information that bring geophysicists and reservoir engineers together and focus the conversation on key remaining uncertainties such as fault transmissibilities and drainage areas. Time-lapse observations can confirm the key conceptional models already in place but are even more valuable when they highlight alternative models that have not yet been considered. The lessons learned from the acquisition, processing, analysis, interpretation, and integration of the data are shared. Some of these lessons are reiterations of previous work, but several new lessons originated from the latest 2019 acquisition. This was the first survey in which independent simultaneous sources were successfully deployed to collect a time-lapse survey. This resulted in a much faster and less expensive acquisition. In addition, full-waveform inversion was used as the main tool to update the velocity model, enabling a much faster turnaround in processing. The fast turnaround enabled incorporation of the latest acquisition to better constrain the velocity model update. The updated velocity model was used for the final time-lapse migration. In the integration part, the 4D-assisted history-match workflow was engaged to update the reservoir model history match. All of the upgrades led to an overall faster, less expensive, and better way to incorporate the acquired data in the final business decisions.

Innovation and instrumentation in CO2 monitoring wells for reservoir surveillance and advanced diagnostics

2021 ◽  
Vol 61 (2) ◽  
pp. 530
Author(s):  
Paul Barraclough ◽  
Mohamad Bagheri ◽  
Charles Jenkins ◽  
Roman Pevzner ◽  
Simon Hann ◽  
...  
Keyword(s):  
Carbon Capture ◽  
Gas Injection ◽  
Water Injection ◽  
Carbon Capture And Storage ◽  
Injection Well ◽  
Fibre Optics ◽  
Monitoring Wells ◽  
Co2 Monitoring ◽  
Optic Systems

In 2015, CO2CRC Ltd embarked on an ambitious plan to field test innovative technologies to monitor a CO2 plume injected into a saline aquifer with a view to address many of the economic and environmental concerns frequently associated with commercial carbon capture and storage project’s long-term monitoring programs (Jenkins et al. 2017). It was called the Otway Stage 3 Project and it was focused on testing the technologies of seismic and downhole pressures applied in unique ways to monitor an injected plume of approximately 15000 tonnes as it developed and migrated in the subsurface. To achieve this goal, five new wells were drilled at CO2CRC’s Otway International Test Centre – one dedicated to injection (drilled in 2017) and the remaining four wells (drilled in 2019) were used for monitoring purposes. Each monitoring well and the gas injection well, were outfitted with fibre optic systems installed and cemented outside the casing (specifically for seismic monitoring) and with pressure gauges installed at the reservoir depth. The challenge of the installation was to install fibre optics outside of the casing, cement them in place securely and to perforate the wells without damaging the fragile TEF bundles. While the installation of the pressure gauges in the injection well was a conventional in-tubing gauge mandrel, the installation in the monitoring wells, which were to be used for water injection as well as pressure monitoring, used a less conventional deployment method, where the gauges were instead installed using a more economic and flexible approach by suspending the gauges from the wellhead via a hanger system. This not only ensured continuous offline monitoring of the downhole well pressures and temperatures, but also facilitated future well operations by simple wireline retrieval and deployment of the gauge, forgoing the need for a workover rig. The various systems were commissioned over the period of March–June 2020 and were in full operation in the second half of 2020 – all successfully operating and acquiring baseline data remotely as designed. The Stage 3 Project commenced gas injection operations in December 2020 and data acquisition using the innovative systems have commenced successfully.

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