SWF cement jobs only as good as well design

If a cement job leaves gaps nears a shallow water flow zone, these spaces can provide a channel to conduct the pressurized water and flowable sands back to the surface, washing out the well. [36,031 bytes] The automated foam cement program described above has become the industry standard for dealing with shallow water flows. [45,614 bytes]

Is foam removing some guesswork?

William Furlow
Technology Editor
Although nitrogen injection has become fully automated and is now the accepted standard for cementing through shallow water flow (SWF) zones, other factors affecting the process are not so cut-and-dried. To properly cement through a shallow water flow zone, service companies say operators need to consider the bigger picture.

There is no greater recipe for disaster, according to BJ Services, Dowell, and Halliburton, than to neglect the interaction of the various downhole systems that include a cement job. The three say it could be a mistake to call in someone to troubleshoot the cement job on a well.

Everything from site selection to the choice of muds and sweep fluids plays a role in the success of the cement job. Without input into all, or many of these areas, a service company is working at a disadvantage when it is time to cement.

Sweep and clear

A cement job is only as good as the sweeps that go before it. In turn, the sweeps have to be matched to the proper drilling fluid, which of course has to be carefully selected to match the well conditions and characteristics of the formation. If the mud is wrong for the formation and the sweeps can't clean it out, then the remaining mud cake will act as a barrier between the formation and the cement.

This will, in turn, create a channel to the surface. This is big trouble and can lead to a washout or communication between several wells. If the casing is not properly centralized before cementing, then a channel could develop where the cement is thin.

Shallow water flows generally occur within 2,000 ft of the mud line. This is significant also, because an upper casing string is typically jetted in and not cemented. This means that if a flow escapes around the isolated second casing string, the upper casing can transmit flow pressure to the surface, transporting not only pressurized water, but flowable sands.

This event could lead to what Tom Griffin, Cementing Technical Advisor for Schlumberger Dowell Wellbore Construction Services, calls turning the hole inside out. Operators are fond of batch-setting conductor casing through the shallow water flow zone, identified by either seismic readings or a pilot hole. While this may be an inexpensive way to drill a number of wells quickly, it is very important that this initial casing string receives a good set, since it is not cemented and typically only set to about 2,000 ft below the seabed.

Proper drilling fluid

Griffin said the service company must choose the proper drilling fluid - one that will not invade or damage the formation. Before running the cement job, it is essential that the well be killed and in a static state. Then the spacer or sweep is circulated with returns to the sea floor. These returns must be verified by remote operating vehicle inspection.

Once the formation pressure is determined, the proper weight for the cement is established and the nitrogen injection program designed accordingly. The operator then clears the mud out with an effective sweep, centers the casing string with spacers and runs a properly weighted, properly formulated foam cement.

If these procedures are followed, then the chances are good that the cement job will hold and the drilling program can continue past the SWF zone. A weakness in any of these areas may result in the creation of a channel to the mudline, leaving open the potential for wash out.

Best practices

Because there is so much at stake in deepwater exploration drilling, many service companies promote a systems approach to drilling. Halliburton and Dowell would like to be involved in every stage of the process to ensure they understand and can influence all the variables listed above.

There are two facets to this approach. If a service company is sweeping a mud it designed for a cement it also designed, there should be no surprises in performance or effectiveness. On the other hand, if the service company comes in for the cement operation alone, not only does the company have to rely on the competence of others, but cannot be certain that the cement job it does will not be affected by what had gone downhole before.

If such an integrated approach is not available, then the priority becomes best practices. This means calling on experience and technology to make sure the mud cake is dissolved and removed and the cement job is of the proper weight and chemistry.

Halliburton sells a mud management system, for example, that includes settable kill fluids, foam sweeps, or spacers and a specially designed cement. Other service companies offer similar lines.

Who is using what

Ronnie Faul, Technical Analyst with Halliburton, said their system, based on the use of foam cements, has a success rate of 98%. The foam is produced by an automated nitrogen injection system that ensures a consistent density. Such a system, in one form or another, is used across the board on such jobs. In fact, many of the new rigs under construction or conversion will be equipped to accept an automated nitrogen injection system in addition to the typical cementing equipment.

The base cements differ among service companies. Typically, the base is a Portland cement, but in deepwater conditions, it is difficult to get a conventional oil well cement to perform at the low temperatures encountered in deepwater.

The service company has to find a base cement that is aggressive enough to set up at very low temperatures, near freezing. Traditional base cements such as the Class G or H are just too sluggish, according to Dan Mueller, Senior Leader of Cementing R&D for BJ Services.

Halliburton uses a patented Class A microfine base cement, Dowell uses a Class A or C, BJ Services uses an ASTM Type I/II. Once a company identifies the appropriate base cement, it must choose an accelerator. These chemical additives control thickening times and compressive strength development at the low temperatures in deepwater.

Common accelerators include calcium chloride, seawater, or salt. Dowell uses gypsum. BJ uses metakaolin. While all the cement companies use these generic additives, the specific formulas vary from company to company. Each uses a different specialized product for acceleration and each uses a different base cement. The materials are common, the trick is to match the right base cement with the proper additive to produce an adequate thickening time and compression strength.

Foam cements are compressible and dynamic, and by altering the amount of nitrogen in the mix, an operator can vary the cement density at will. This offers major cost and time savings because the base cement on the rig can be used throughout the cement program with the density regulated by varying the nitrogen content.

Once a cement formula is designed, the service company has to devise a way to control the flow from the shallow water aquifer while the cement sets up. Additives cannot completely block a shallow water flow, but they can inhibit it. Mueller said polyvinyl alcohol (PVA)is a common flow inhibitor that has the advantage of being non-retardive, meaning it will not affect the thickening time of the cement.

Transition time

The transition time for these cements is critical because the flows are initially being held back by the hydrostatic head of the liquid cement. During the transition time, the cement thickens and solidifies. As this occurs, the hydrostatic head dissipates and the static gel strength of the cement increases.

As the cement reaches a gel strength of 100 lb/sq ft, it loses the ability to transmit hydrostatic pressure. At 500 lb/sq ft, the cement reaches a gel strength great enough to prevent fluid influx. It is between these gel strengths that the greatest risk is encountered. This is the period Halliburton and other service companies hope to minimize. One material - meta-silicate - has been successful in shortening this transition time slightly, but according to Mueller, there are too many factors affecting this transition time for any one additive to have a dramatic affect. Once a base cement is chosen and additives are formulated to produce an optimum cement, the final step is to foam it by injecting a controlled amount of nitrogen. A successful foamed cement should have a uniform bubble size. This produces a stabilized foam that is consistent. The PVA acts as a foam stabilizer as well as a flow inhibitor. Once a cement is foamed, the rheology is higher than it is in the liquid form. The foam also imparts thixotropic properties to the cement, which is the key to holding back shallow water flows. Foams are able to combat the flows better during the transition time. The foam provides additional viscosity and a compressible phase that makes the cement column more resilient. Foams are also good at displacing fluids, so a foam lead cement can help remove residual mud and other materials from the annulus ahead of the main cement job.

Dowell has developed what it calls a right-angle setting cement. This product acts counter-intuitively to other cements in that it hydrates faster in cooler temperatures. This offers a distinct advantage in deepwater conditions where a cement is mixed on the deck of a rig at about 80°F, then pumped downhole to the mudline where temperatures are near 40°F, then into the formation where temperatures gradually rise. Faul said one of the biggest challenges for cementing in deepwater was the variety of temperatures involved in the process. It takes a special cement to set up at downhole temperatures of 40-50°F. Generally cement doesn't hydrate at these temperatures.

API standards

Griffin said one of the biggest challenges to advancing the understanding of downhole temperature gradients in deepwater fields is a standardization of pressures used to test the cement slurries in these fields. He said the existing American Petroleum Institute standards currently in place do not take into consideration the cooler temperatures at the mud line.

Griffin said he suspects the temperature gradient below the mudline in deepwater fields may also deviate from the standard. Dowell and other service companies have developed a cementing simulator to assist field personnel in designing a cementing program. Unfortunately, such simulators are only as good as the data they are working from. What is needed is an accurate profile of deck temperatures. These data could then be plugged into the simulator to predict the temperatures the cement will encounter from the rig floor traveling through the sea currents and colder temperatures at the mudline.

It is this temperature range that is important in calculating the formula of the cement, because the slurry will travel through all of the temperatures in between during its trip down the hole and back up the annulus. A joint industry project aimed at establishing a data base of these readings that could be incorporated into simulation programs to give more accurate predictions.

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