Many strategies exist for controlling or mitigating water production. Each has its advantages. The trick is figuring out which solution is best for your well.

John Warren, Commercialization Manager, Near Wellbore Stimulation, Halliburton, Houston

A major challenge in today's petroleum industry is minimizing the amount of water that enters a well bore and is subsequently produced. Fortunately, many strategies and solutions are currently available, some involve mechanical tools while others use cement or chemicals to manage unwanted water production. However, many operators do not consider these solutions and technologies when they want to reduce unwanted water production and improve overall field economics.

To appreciate what is new in water management, it is important to understand the global impact produced water has on the oil and gas industry. It is estimated that in 1999 an average of 210 million bbl of water was produced each day worldwide.

A large percentage of produced water is used for pressure maintenance and enhanced recovery. A 1995 API study found that management and disposal of exploration and production waste was following a trend toward less discharge and more reuse, recycling and reclamation. API's study indicated that about 71% of all produced water was being injected for enhanced recovery while 21% was being injected for disposal. The remaining 8% was treated and discharged, disposed of or beneficially used.

If the sheer volume of produced water does not cause our industry to take notice, its financial impact should. Costs can run from US $0.02/bbl to as much as $2.50/bbl, depending on location and volume. Accordingly, the average cost to produce 1 bbl of water is $0.10, making the annual expenditure $7.7 billion. In addition, produced water results in lower production rates, a reduction in recoverable reserves and potential negative environmental impact.

Sources of unwanted water production

Unwanted water production can be divided into two major groups; near-wellbore and reservoir, the first being fairly straightforward and the latter being a bit more difficult.

Near-wellbore sources of water production include:

• Casing leaks
• Channels behind pipe
• Barrier breakdowns
• Completions into or near water

Reservoir-related problems include:

• Coning and cresting
• Channeling through high-permeability streaks
• Fingering
• Out-of-zone fractures
• Fracture communication

Mechanical shutoff methods

To understand what can be done to keep water out of the well bore, we must first know what is available in the industry. Current mechanical shutoff methods include:

• Bridge plugs
• Straddle packers
• Tubing patches
• Cement
• Sand plugs
• Expandable tubulars
• Resins/particulate chemical blends

Most of these methods have been used for years, and under the right conditions, can successfully reduce an influx of unwanted water. Often operators do not commit sufficient time and expenditure to diagnose and apply a mechanical isolation technique appropriate to the conditions. The bottom line is that a mechanical solution will not work for all water shutoff challenges. For example, applying a mechanical solution to a reservoir-related problem normally will not succeed.

Chemical shutoff methods

Reservoir-related water production can sometimes be solved using:

• Micro matrix cements
• Polymers
• Micro particle blends
• Foamed systems
Water reduction methods:
• Relative permeability modifiers
• Oil/water separation

Understanding the problem is critical

One highly challenging aspect of water management is that each well, reservoir, field and application is unique. To determine which solution is best, you must first understand the nature of the problem. In areas where diagnostics is a primary focus, operators are often more successful in resolving their water production problems. Many diagnostic tools and techniques gather information for formation evaluation and fluid flow analysis, including these types of data:

• Porosity
• Water saturation
• Casing integrity
• Cement integrity
• Fluid movement
• Fluid composition
• Specialty visualization

After these data are collected, they must be interpreted. Standard log interpretation can be performed by the service provider, the operator, or both. But then what can be done? A log analyst will not tell you how to solve a near-wellbore problem, or even that you have a near-wellbore problem.

Proven methodology for controlling unwanted water production

1. Determine that you have unwanted water.
2. Diagnose the problem.
3. Design a solution.
4. Perform the treatment.
5. Evaluate the results.
Tools and processes exist to help with each of these steps, but how do we then determine whether a solution is applicable before performing a treatment? How do we determine that a solution has the potential to produce a financial benefit? This can be evaluated to some extent through reservoir simulation. For older wells, most operators will not invest the time and resources needed for reservoir simulation.

Advancements in water management technology

New Water Management Treatment Simulator

What if we could take diagnostic information from a well, simulate a treatment or shutoff operation, and accurately predict the results of the operation? A new simulator offers a unique combination of features that can help optimize the design and placement of water control treatments and predict their effects on production (Figure 1). By numerically simulating the flow of oil, gas, water, conformance fluid and heat through a porous medium in three dimensions, the simulator enables initial reservoir conditions to be quickly and easily set up. A number of wells with various flow constraints can be handled simultaneously. The simulator's local grid refinement works both horizontally and vertically to model near-wellbore effects such as those caused by conformance fluid injection, coning, or field-scale simulations. In addition, the simulator can model deeper reservoir effects such as those from communication through a fracture or a high permeability streak. And, it accurately models conformance fluid placement by incorporating the thermal and fluid viscosity effects in both the reservoir and the well bore.

The new simulator was developed to optimize the design and placement of treatments to shut off production of unwanted fluid. As the only reservoir fluid management technology created specifically for oil industry conformance applications, it allows data to be interpreted with unprecedented speed and accuracy. Processes that once took days or weeks to complete with a typical reservoir simulator now require only a few hours. Using this revolutionary approach, you can predict the economic outcome and make quicker, more accurate and more proactive decisions to maximize production and efficiency.

The new simulation software is exceptionally versatile. Its reservoir fluid-management tool has a superior graphic interface that enables operators to enter complex well data, check data consistency, produce supplemental plots, display interactive graphics, launch and monitor simulation runs, and analyze results.
Simulator capabilities include the following:

• Production history matching evaluated against wellbore and reservoir diagnostics to more accurately determine well and reservoir flow characteristics.
• Water shutoff or reduction design maximized and simulated based on reservoir characterization from simulation and history match.
• Forecasting of production resulting from treatments applied to both simple and complex reservoirs and/or wells.
• Reduction of economic and operational risks through better candidate selection, diagnostics, evaluation, and treatment.

New Relative Permeability Modifier

In addition to an improved capability to diagnose, evaluate, and simulate, a new treatment system has also been introduced (Figure 2). The new system can be bullheaded into a well to greatly reduce permeability to water with little or no restriction to hydrocarbon flow. This new approach uses unique polymer chemistry to help create oil-water separation in the reservoir, thereby impeding water flow and enhancing hydrocarbon flow to the well bore. Called a relative permeability modifier, the polymer works by adsorbing onto the rock surface and reducing permeability to water by a factor of seven to 10 compared to hydrocarbons.

Features of the new treatment include:

• Requires no special placement techniques;
• Unaffected by multivalent cations, oxygen, and acids;
• Does not require rig time, zonal isolation, or a catalyst;
• Does not gel or "set up."

This treatment can also be incorporated into the new simulator to determine whether it is the best technical and economic solution for the well.

Summary

Today, a full range of solutions is available for almost any near-wellbore or reservoir-related produced water challenge. In addition, a range of tools and techniques is available to properly diagnose wellbore and reservoir characteristics. Most importantly, a new treatment simulator has been developed that enables us to determine which treatment will provide the best overall technical and economical solution. By working together, service companies and operators can reduce overall water production effectively with an attractive economic return to the operator. But in order to move forward, the industry must understand that the impact of produced water is much more significant than currently recognized and that the problem is manageable.