Approach to Improve and Optimise Deepwater Waterflood Projects in 2011
model to calculate the injection rate and bottom-hole pressure using a specified injectivity index obtained from the injector modelling study.
As an example of building injectivity maps, Figure 4 plots the injection rates achieved for different injectivities. The required injection pressure topside was estimated at a maximum of 8,500psi and the injectivity index values were obtained from the well injectivity study. Values of 2.5, 3, 3.5, 40 and 4.5 barrels/day/psi (bbl/d/psi) are used in this example.
Improving the Injection Design Plan for the Reservoir Facing an offshore waterflooding project implicates significant capital expenditure (CAPEX); therefore, obtaining a better understanding of the reservoir dynamics, improving reservoir characterisation and providing information to facilitate well management, reservoir performance tuning and overall optimisation of the field are crucial.
The technique of monitoring water injection by the use of tracers has been applied in numerous fields worldwide: during pilot stages of new flood projects, when operational problems begin to occur, to evaluate conformance treatments and for anticipation and evaluation of the progress of potential problems. An inter-well tracer programme to enhance reservoir interpretation is critical during the design and operation of recovery projects, since tracers provide a direct way to measure and track fluid movement in a reservoir at a relatively low cost compared with offshore facility construction costs.
Modelling tracers using numerical reservoir simulation techniques such as streamline models (usually during the design stage) is a proven and effective method to determine flow relationships and communication pathways between the injection and producer wells and predict the time to initial tracer breakthrough at the producers. Furthermore, streamlines serve as the basis for future tuning of the full field reservoir model by incorporating the data obtained from the tracer field test results and providing a way to compute the tracer arrival in a well through the time of flight (TOF) relationships between injectors and producers.
In addition to all the above-mentioned benefits of the tracer programme during the FEED phase of the project, some of the advantages provided by this technology are: detection and quantification of fracture/fault communication, determination of sweep efficiency of the flood, identification of the presence of high-flow permeable channels and measurement of floodwide reservoir preferential flow trends, among others. An example of modelling inter-well tracers for a water injection project assisted by streamline simulation is presented in Figure 5.
Closing the Loop
The next fundamental steps involve closing the loop with the reservoir and the facilities and drilling/completions teams. The reservoir and geological characteristics of the field dictate the water injection requirements. If waterflooding has been identified as the most appropriate way to improve production and recovery in a field, the proposed water injection scheme is evaluated to indicate the sufficiency of the topside design to provide the required injection capacity to meet oil production targets. This must be coordinated with the subsurface strategy to maximise oil recovery and minimise water production. In one sense, the reservoir team represents the ‘client’ and provides the injection water requirements to be fulfilled for optimal reservoir performance.
EXPLORATION & PRODUCTION – VOLUME 9 ISSUE 1
Figure 5: Streamline Model to Simulate Inter-well Water Tracer Injection X
P-8 Z I-1 P-4 I-2 I-3 P-18 P-1 P-6 P-3 P-17 P-5 P-10
Streamlines Well Pair Association
As noted, injection-induced fractures can grow with time and have a significant impact on reservoir sweep, particularly in multilayered formations. Injector performance simulations should provide the reservoir team with the likelihood of injection-induced fracturing and fracture length over time in each of the layers. These findings can then be taken into account in subsequent reservoir simulation studies.
Although decisions made by the facilities team are largely determined by the results obtained from the injectivity study and the reservoir and drilling/completions teams, the facilities team also has a significant impact on the success of a water injection project. The input for required water quality specifications comes from long-term injector performance simulations, which provide injectivity sensitivity to water quality and can be used to specify water quality requirements. Once water quality is specified and injection rates are set, the water treatment options can be evaluated and designed. Different planning scenarios may need to be considered for seawater versus produced water injection.
The drilling and completions team is a key player in planning and designing a waterflood. Decisions about wellbore configurations, tubing sizes and completion design are determined, in large part, by specified injection rates and reservoir properties. Completion decisions are particularly difficult if sand control issues are expected, requiring cased-hole gravel packs, frac packs or other completion options. Downhole flow control devices are another key element in the decision process. For horizontal injectors, bore-hole orientation and length must be planned. Because these completion decisions have a direct impact on waterflood performance, they must be integrated into decisions regarding water quality specifications and injector performance.
The final element in the process is systems integration and design/implementation decisions. Because there are several diverse aspects to the problem, the team must integrate several critical elements during the project’s design and implementation phase. These include:
• injection well location, type and orientation (horizontal versus vertical); •
•
• •
injection well completion (tubing size, completion type, flow control devices);
topside pumps and facilities (injection rates and water quality specifications);
subsea (risers, wells, subsea field layouts); and
subsurface (injection rates and pressures, field development plan, expected reservoir performance, flow relationships/communication between wells, impact of fractures on reservoir sweep and oil recovery, integration and installation requirements). n
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