Issues in Waterflooding: Part II – The role of the asset team in developing the field management plan
Posted by D Nathan Meehan October 29, 2010

The asset team responsible for optimizing the value of a field under waterflood doesn’t have the ability to change the existence of reservoir heterogeneities but must recognize them and properly characterize them in the static and dynamic models. They utilize the results of pre-existing reservoir monitoring data and recommend optimal data gathering to improve their ability to analyze performance and predict future performance under a variety of operating conditions. These various conditions generally include a “No Further Action (NFA)” case in which additional capital expenses are minimized. An NFA case doesn’t mean that no actions are taken; NFA refers to operating the field under a fixed set of guidelines requiring minimal capital.

The set of guidelines that describes how a field is operated can be viewed as the “operating instructions” (OS) or Field Management Plan. These would include the producing constraints, the frequency of measurements and actions to be taken. An infill drilling campaign contains a set of instructions to drill, complete and equip a certain number of additional wells in addition to how existing wells are produced. It is rare that operators have a formal, detailed OS covering all aspects of field performance. A field OS is designed to optimize production rates, recoveries and total expenses leading to the optimization of a certain utility function we can call F. Many operators strive to optimize NPV for example. In a typical field, NPV is a function of product prices, taxes, royalties (over which the operator has essentially no control), production rates, operating costs, capital costs and other variables the operator may influence. A waterflood OS would specify which wells to convert to inversion, new wells to drill, intervals to perforate and how completions will be designed to optimize injection and production, design production rates, testing and review procedures, etc. Detailed reservoir monitoring plans are essential to provide the operator with feedback on how the reservoir is responding to the actions specified in the OS. In concept, the OS describes procedures for interpreting reservoir monitoring results (perhaps the relative injection rates by layer) and how to respond to variations with respect to the plan. Actions may be minor (such as selectively restricting flow into a high permeability layer) or lead to detailed reservoir studies by the asset team. An NFA case has what amounts to the simplest set of operating instructions.

An example NFA case might stipulate that water injection remains at VRR=1 for the field, producers are pumped off (produced at the highest rate possible) subject to GOR constraints, that producers testing above a certain water cut have production logs run and evaluated for selective shutoffs or abandonment, that water injectors whose injectivity index declines more than a certain percentage from current values are evaluated for acidization and that the field be re-evaluated in a few more years. NFA cases have operating constraints that are generally easy to model in modern reservoir simulators and the forecast of oil, gas and water production along with the estimated operating costs are used to quantify the “base case” against which alternative scenarios are evaluated.

The real value of an integrated asset team is its ability to identify alternative scenarios that generate incremental value, increasing oil rates and recoveries, lowering water cuts and operating costs, etc. Often these involve capital and/or operating costs which must be justified. It is impossible to describe all possible alternative scenarios; a few examples include:

  • Infill drilling to tighter densities,
  • Realigning pattern boundaries,
  • Converting some wells to horizontal or multi-lateral wells,
  • Adding intelligent well applications such as inflow control devices, downhole flow rate measurements or fiber optic distributed temperature systems,
  • Changing injected fluids from water to and enhanced oil recovery process such as Alkali-surfactant-polymer or CO2 flooding.
  • Changing artificial lift from beam pumps to ESPs to increase recovery rates and efficiencies and lower costs,
  • Automate corrosion monitoring and injection to lower operating costs,
  • Selectively stimulate producers or injectors, etc.

In each case (and the many more potential actions) it will be possible to forecast future oil, gas and water production and generate another recovery and economic forecast that is evaluated based on its incremental value compared to the NFA case.

3 responses | Add Yours

Responses

pele okulo says:

very nice article
I am currently doing waterflooding for newfield exploration in the Utah Buttes field. Heavy oil 10 API lots of infield drilling
Any more articles?

Thanks
Pele

D Nathan Meehan says:

Thanks for the note. Turns out I have a lot of time in waterflooding fairly heavy, viscous crudes. I can address some of those experiences soon. If you have a specfic question I will try and connect you with the right solutions at BHI.

The real issue isnt the density of course, it is the viscosity and low mobility ratio viscous crudes have. This tends to require closely spaced wells and many pore volumes of injection. When thermal recovery is not an option there have been successes in CO2, caustic and surfactant floods to reduce Sor. Tough applications for polymers to improve volumetric sweep, but it is critical to know the areas being swept. BHI has a lot of tools to help in this regard

Eziulo says:

Thanks Nathan for the article. I am a postgraduate student in petroleum geoscience. I will like to know the drilling and data collection program for a 5 spot waterflood pilot which will enable me assess the potential to increase oil productivity by water injection.

Many thanks
Eziulo

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