Acrylate monomer solution stops artesian water, geopressured sand flows

Larry Eoff, James Griffith
Halliburton Energy Services Inc.
Duncan, Okla.

Operators drilling in deep water off the continental shelf can use an acrylate monomer solution (AMS) to stop artesian water and geopressured sands from flowing into the well bore.

Unchecked water flows can wash cement away from casing, making cementation of conductor pipe expensive and sometimes impossible.

AMS is effective in downhole temperatures ranging from 50 to 200° F. It is pumped into a well as a water-thin liquid, but soon becomes a highly gelled, rubber-like solid that serves as an impermeable barrier against overpressured waterflows.

The solution can be mixed to provide variable gel times, based upon the temperature of the formation. Once it has formed a barrier, the operator can drill through the AMS mass and later cement conductor pipe into place without an influx of artesian water ruining the cement job.

AMS works by simultaneously reducing the permeability of a sandstone formation while consolidating the formation's structure into a cohesive mass. The solution can be formulated with fluid densities up to 18 ppg and can be used to stabilize large areas to help stop the cross-flow of artesian water between wells.

The solution may be especially attractive for drilling well templates where seismic tests and other data have shown the presence of artesian water sands.

Background

In 30-40% of deepwater drilling operations in the Gulf of Mexico, operators encounter flows of artesian water in formations less than 2,000 ft below the mudline (BML).

These formations are geologically young, a result of sands and silts eroding from the continental shelf and settling over older, deepwater formations (Fig. 1 [35,497 bytes]). The younger formations are often highly permeable and can act as conduits for overpressured water.¹

Deepwater operators have often found matters complicated by numerous overpressured zones with very low fracture gradients. A cement slurry, designed to be dense enough to control the artesian water, may be too dense to be supported by the formation.

AMS can help to increase the fracture gradient, but not as effectively as an epoxy resin. Thus, AMS is more applicable in the reduction of formation permeability.

State-of-the-art cementing

One successful approach applied to stopping artesian water flows has been to cement conductor casing using a lightweight, foamed slurry with good compressive strength in combination with settable spotting fluids.

The compressible nature of the foamed slurry helps to control water flow, yet is not so dense that it causes formation fracturing. The settable spotting fluids provide for high mud displacement during the cementing process. The settable spotting fluid is formulated with hydraulic material so that if the fluid is not all displaced by cement, whatever fluid is left over will simply solidify.

Key factors in using state-of-the-art cementing to control water flow include:

• Proper hole preparation. Properties of well bore fluids are critical. It is essential in planning the formulation of a well-bore fluid to improve the likelihood that the cement slurry will be able to displace the well bore fluid and seal the conductor-well bore annulus.

Operators have met with success by lowering the gel-strength profile and fluid loss of the spotting fluid with a starch fluid-loss control agent. To improve sealing of the annulus even further, operators often add an hydraulic material to the spotting fluid.

This fluid remains liquid for 7-10 days, but sets within hours after the cement slurry is placed. Any filter cake or fluid not removed by the cementing process will solidify, providing for better sealing of the annulus.

• Cement slurry design. The lightweight, foamed cement slurry must be dense enough to control formation influx, while not contributing to the possibility of formation fracture. Typical ranges of slurry density should fall within the gradient window between formation pore and fracture pressure.

In addition to hydrostatic pressure for well control, incremental hydrostatic pressure should be designed into the slurry to compensate for the reduction in pressure that will take place while the slurry is undergoing hydration.

While state-of-the-art cementing has been effective, especially in shutting off flows of artesian water into individual well bores, it has not been an effective approach to site stabilization. There have been cases when mud channeling in cement sheaths has compromised the seal of the annulus, resulting in water cross-flowing into shallower sands, or breaching previous casing shoes.

Wells drilled in a template have been compromised by cross-flows of water from one cemented well to another. In the case of a cross-flow, the stability of an entire site can be compromised and operator losses can easily run into millions of dollars.

A better way to ensure the isolation of water and geopressured sand in a high-permeability sandstone would be to pump AMS into the formation, and then follow the AMS treatment with state-of-the-art cementing techniques.

Past uses

In the past, AMS has been used most often in conformance operations, to reduce or plug water flows into hydrocarbon-producing wells or injection wells with bottom-hole injection temperatures (BHIT) between 65 and 200° F. (18-93° C.).

It is usually a 15% monomer solution (optionally up to 20%) pumped into a formation at matrix rates, and can be batch-mixed or blended on the fly. Temperature-activated initiators cause AMS to change from liquid to solid at predictable times at known BHITs.

AMS can be formulated in seawater and a variety of brines. With heavy-weight brines, final AMS density can go as high as 17.0 ppg. In conformance applications, AMS can be used to:

• Minimize waterflood channeling and CO₂ channeling, seal pinhole casing leaks, and seal channels behind pipe.
• Seal high-pressure zones and control gas migration and lost circulation at the kick-off point in deviated wells.
• Stabilize subsiding zones and fault zones.

Before the AMS can be used in conformance applications, operators must determine the presence of natural or induced fractures, vugs, or high-permeability streaks. A BHIT profile of the well is critical to correctly formulate an AMS treatment for volume and placement rate.

Operators have used the solution in weighted and slurried forms to aid in conformance. They can choose the concentration of initiator to initiate in situ polymerization throughout the entire treatment soon after pumping is complete.

They may also choose to formulate the solution so that the leading edge of the treatment will begin polymerizing shortly before pumping is complete, allowing for squeeze pressure and diversion of the solution into less-permeable zones.

Operational use

AMS may be used to accomplish zonal isolation in an offshore drilling operation once casing has been set, typically several hundred feet BML. During a normal riserless operation in the Gulf of Mexico, operators will jet-in a 30-in. drive pipe to a depth of about 300 ft BML.

Seawater used as drilling fluid is forced under pressure through the annulus between the drive pipe and the well bore, back to the ocean floor (Fig. 2 [44,625 bytes] ). After a target depth is reached, the drive pipe is held in place by silts washed away from the sides of the well bore. The drive pipe is not cemented.

A mud mat is set in place at the mud line (Fig. 3 [43,566 bytes]). Drilling is continued with a conventional drill pipe below 300 ft. Lengths of 26-in. conductor casing are set below the drive pipe as the hole is drilled deeper. Seawater, cuttings, and other fluids are forced out of the well bore through the annulus between the conductor casing and drive pipe (Fig. 4 [40,780 bytes]).

In typical GOM deepwater drilling operations, high-permeability sand zones and artesian water flows can be expected at depths of about 600 ft BML. Operators working with seismic data or data collected from offset wells will often know in advance of drilling where such zones are located.

Ideally, they would stop drilling just before reaching a high-permeability zone, run casing, and then cement the 26-in. conductor pipe into place (Fig. 5 [73,435 bytes]). With the artesian sand exposed by the drilling process, operators would proceed with the AMS treatment (Fig. 6 [80,079 bytes]).

After the AMS gells, drilling continues through the AMS barrier, followed by cementing of the casing string through the treated sand (Fig. 7 [76,758 bytes]). In a riserless system, overbalanced placement techniques would be used to spot AMS into the problem reservoir.

In other applications, packers would be set on the drill pipe to isolate the well bore and artesian water sand. AMS added through the drill pipe would essentially flow into the reservoir, assisted by hydrostatic pressure created by surface pumps.

The AMS, formulated to gel at the appropriate BHIT, would form over a matter of hours into an impermeable mass. As drilling continues, 20-in. conductor casing would be added to extend through the AMS and sand reservoir. After drilling the conductor hole to about 1,500 ft, operators would use state-of-the-art techniques to complete cementing of 20-in. conductor casing.

An effective AMS treatment is contingent upon:

• Good penetration of the treating fluid into the sandy reservoir
• Uniform or nearly uniform radial penetration away from the well bore
• Sufficient penetration of the formation in order to withstand the pressures of any cross-flowing water and sand
• Adequate strength, adhesion, and elasticity of the treating fluid to form and maintain an effective seal in the formation.

Reference

1. Griffith, J.E., and Faul, R., "Cementing the Conductor Casing Annulus in an Overpressured Water Formation," paper OTC 8304 presented at the Offshore Technology Conference, Houston, May 5-8, 1997.

The Authors