Approach to Improve and Optimise Deepwater Waterflood Projects in 2011
Figure 1: Permeability and Porosity Reduction Due to Particle Deposition from the Injection Water
External filter cake Internal filter cake
needed as well as thermal and mechanical properties. The completions group may also need a different set of formation and fluid properties.
The critical input parameters that determine the long-term injectivity of an injection well (and are needed to simulate injectivity over time) include injection rate, minimum horizontal stress, injection water temperature and the concentration and size of suspended solids in the injection water. Some mechanical parameters are also critical in estimating the changes in minimum horizontal stress over time.
Key issues the water injection team needs to resolve include the long-term injection rate that can be sustained for a given surface injection pressure, the impact of injection water quality on long-term injectivity, flow distribution into different sands, the lengths of injection-induced fractures over time and fracture containment.
Models for injector performance need to be run that account for particle plugging of the formation and fractures. Figure 1 shows a schematic of solids/fines in injection water invading the formation and forming a filter cake in a typical injection well. Solids deposition and filter cakes reduce porosity (φ) and permeability (K), causing bottom-hole pressure to rise above formation breakdown pressure and inducing fractures.
and implementation. Coordinating the design of a deepwater waterflood must be accomplished through interactions between the operating companies, service and consulting companies and research institutions and laboratories.
Communication between all members of the multidisciplinary team is vital to the design effort. In most instances, specialised tools such as fracturing simulators, reservoir and single-well injectivity simulators and integrated injection/production modelling software are used. Different levels of expertise in the various groups represented on the team can result in an incomplete understanding of the key issues. Therefore, it is important to open the lines of communication through face-to-face meetings with the different groups to facilitate open dialogue so that reservoir engineers, drilling engineers and facilities engineers all clearly understand how their efforts are interconnected.
Data Requirements
In regard to data collection and quality control, the water injection project team is typically handed a preliminary or advanced development plan that has been prepared and perhaps partially implemented by the asset team. This document is central to planning the asset development and revising it to include a water injection programme is the water injection team’s primary deliverable.
The development plan includes details about proposed production and injection well locations, target production and injection rates and preliminary reservoir simulations that show a cost/benefit analysis of developing the field in different ways. It will likely contain all available data on formation and fluid properties. It is important to allow the discipline managers to present the data to the water injection team so that any inconsistencies can be addressed and questions or uncertainties clearly established at this early stage of the programme. Each member of the team will have different data requirements, which need to be recognised early. Some of the data requirements might be quite different to those needed for a typical reservoir simulation. For example, to simulate the performance of the injector, flow properties are
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Thermal injection-induced fractures are created and propagated by cold injection fluid cooling the formation surrounding the injection well, reducing the in situ stresses to below the bottom-hole injection pressure. The major parameters that determine thermal fracturing are the stiffness of the rock, characterised by Young’s modulus, the rock’s linear coefficient of thermal expansion and the temperature difference between the injection water and the reservoir.
Injection-induced Fracturing
A growing realisation is that almost all injection wells develop injection-induced fractures at some point in their lives. In cases where the well has been deliberately hydraulically fractured, injecting water with fines for an extended period causes the bottom-hole pressure to rise above the formation breakdown pressure and extend the existing fracture. Induced fracture growth is driven by particles in the injection water plugging the formation (which can result in increased injection pressures) and thermal stresses (which can reduce the formation breakdown pressure). As injection pressure exceeds the formation breakdown pressure, a fracture begins to propagate. The rate at which a fracture grows is controlled by water quality and reduced minimum horizontal stress induced by injecting cold water. Poor water quality with high solids/fines concentration usually results in long induced fractures and low well injectivities.
Fractures created in water injection wells differ from hydraulic fractures in many ways. Particle plugging and thermal stresses play insignificant roles in hydraulic fracturing, since the volume of fluid injected into the fracture is very small compared with a typical injection well. The rate of fracture propagation is also significantly different, with a hydraulic fracture propagating hundreds of feet in an hour compared with months or even years for an injection-induced fracture. Moreover, the viscosity of fracturing fluids is much higher than water. Consequently, the models used for hydraulic fracturing do not directly apply to injection well fracturing and cannot properly account for the effect of particulate plugging and thermal stresses.
EXPLORATION & PRODUCTION – VOLUME 9 ISSUE 1
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