More robust polymer systems give added control over lopsided water-oil ratios.

Solutions for controlling oilfield water production are becoming more effective as the companies who provide them sharpen their focus on more accurate diagnostics. As a result, a growing number of options is available to operators, ranging from simple and relatively inexpensive undertakings to considerably more complex and costly ones.
In the past, water problems usually resulted in eventual well servicing, with the added costs associated with shutting in production and intervening into the well with expensive workover equipment. However, development in recent years of more sophisticated coiled tubing delivery systems has helped service companies increase the placement accuracy and overall effectiveness of many of their downhole products and services - including those used to control excessive water production - without overly extended well shutdowns and disproportionate workover expenses.
Water influx - in the form of casing leaks, flow behind casing, coning and watered-out layers, among others - remains one of the most prevalent problems operators face during the life of a well, and it can occur at any time. Once the problem arises, the operator's goal is to seal off water flow into the wellbore completely, or at least reduce it long enough to extend the well's productive life.
The most common solutions to water production problems include mechanical tools like permanent and drillable well plugs, retrievable and inflatable packers and casing patches; squeeze cementing for zonal isolation; and injection of chemical treating agents, mainly synthetic polymer gels.
The mechanical and cement-based water control solutions continue to be used widely and usually are effective. However, cross-linked polymer gel technology has advanced significantly in recent years to further prolong the economic viability of high-watercut wells.
Gelling off the flow
Marathon Oil Co. research scientists pioneered polymer gel technology for water control. However, recent development of more robust chemical systems and an improved understanding of their applicability has led to even more extensive use of such gels. Not only do they control unwanted water production, but they help improve hydrocarbon production and the efficiency with which it is produced.
Starting with licenses to market products based on Marathon's patented Marcit and Maraseal polymer gels, many oilfield service companies have gone on to develop their own gel-based water control systems.
One such step in cross-linked polymer technology is the patented H2Zero system from Halliburton Energy Services (HES). According to the company, because this polymer uses an organic cross linker, rather than the chromium-based cross linker typical of conventional water control polymers, it sidesteps environmental risks associated with chromium constituents. In addition, the system is specifically designed to give the organically cross-linked polymer (OCP) improved resistance to temperature. The application temperature range for the system is 125°F to 325°F (51°C to 160°C), as compared to conventional polymers, whose average upper end is 200°F to 250°F (92.4°C to 120°C). According to HES, the system also withstands higher differential pressures than conventional polymers.
John Warren, project manager for HES Conformance Solutions, said the OCP originally was developed for the North Sea, where water-oil ratios are high and environmental provisions for produced water disposal can be stringent, which often raises operating costs significantly. Since its initial use there, however, the OCP has been applied successfully in other regions.
In some instances, the water control objective for polymer systems is to shut off water production in the near-wellbore area, said Warren. However, the ability of a gel system to penetrate and have resistance to flow a good distance from the wellbore is important for other water production problems, including high-permeability streaks, coning and cresting.
"Research indicates that CCP (chromium cross-linked polymer) shutoff systems do not always propagate completely into the target zone," he said. "The limited stability of CCPs may contribute to this. At pH levels above 6 to 7, which are typical of carbonate formations or sandstones rich in carbonate, the chromium cross linker tends to precipitate from solution, thus limiting propagation into the near-wellbore matrix."
But because the system relies on the polymer itself - rather than the chemistry of the cross linker - to create cross-linking delay, deeper propagation can be achieved, he said, adding that extensive laboratory research has determined how the system behaves downhole.
Extending the reach
Prior to introduction of the new OCP, Halliburton conducted numerous lab-flow tests to demonstrate its ability to propagate through simulated matrix material. In these tests, stainless-steel tubes were filled with packing material (sand, sand and carbonate, or crushed Berea sandstone), and one pore volume of gel was injected during each test.
"The apparatus provided the option of using up to nine pressure taps along the length of each tube," he said. "Propagation of the OCP system was compared to that of a commonly used CCP, and the resulting resistance to flow at each of the pressure taps demonstrated the higher 'strength' of the OCP. Additionally, the difference in penetration depths was significant (Figure 1)."
Additional testing included the effect on the OCP of different downhole conditions, including temperature, component concentration, brine type, salinity, pH, reservoir fluids and rock types.
Physically, the OCP is easily mixed, Warren said. Because the polymer and cross linker are in solution, they need only to be diluted in the mixing brine. This avoids the lumping problems associated with CCP, which normally is shipped in powdered form for mixing.
Pumping also is simplified, he said, since the initial viscosity of the OCP base fluid is no more than 30 cp. Therefore, friction pressure due to pumping is minimal.
Some cases in point
Introduced in the North Sea area in 1997, the system apparently proved highly effective during the next several years. This was particularly so in reservoirs with high water co-production like Phillips' Ekofisk field and its satellites, where water disposal during early development resulted in excessive subsidence and significantly higher costs associated with eventual replacement of entire production and storage facilities. The Norwegian government instituted new water management regulations, and polymer injection for water shutoff became a highly sought-after service.
Since that time, however, application of the OCP system has expanded into other producing regions with excessive water production problems, offshore and on land. These include the United States, the Arabian Gulf nations, Egypt, West Africa and Venezuela. There have been 91 applications to date, said Warren.
In one application, the system was used to shut off water from a cased producing well in the Egyptian Gulf of Suez's El Morgan field. Gupco, an Egyptian General Petroleum-BP joint venture, operates the well. The application resulted in complete shutoff of more than 3,000 b/d of water from two of the well's 10 perforated zones.
Pretreatment diagnostic tests and reservoir analyses were conducted to develop a full understanding of the issue at the well, which revolved around early water breakthrough, Warren said. He added excessive water production and disposal is a huge problem in the Gulf of Suez, with most wells producing more water than oil. The ability to shut off water production at chosen well intervals, he explained, often means the difference between an economic well and a plugged one.
"Of the 10 zones, the top three had no fluid production, the next four produced 100% water, the eighth zone had no production, and the bottom two zones would produce oil," he said. "The decision was made to isolate the fifth and sixth zones, which were the most prolific water producers, for treatment."
Prior to polymer application, coiled tubing was used to set a sand plug across the bottom four zones, and an inflatable plug was used to isolate the top four zones, he said. The subsequent water shutoff treatment of 16,800 gal of polymer, also placed with coiled tubing, successfully closed the two water zones completely.
"Since the well had been shut in, there was no pretreatment oil production; however, incremental production of more than 680 b/d is now being realized from the four upper zones, while the incremental reserve increase from this production is around 1.5 million bbl," he said.
Shutting off water in gravel packs
In another treatment, this time in the US Gulf of Mexico, the system was applied to a shut-in gas well operated by ExxonMobil in the Mississippi Canyon field. The well was a gravel-pack completion in shaly sand, which Warren said is a historically difficult environment in which to control polymer placement, since it is imperative that no polymer gel migrates through the screen and gravel pack during treatment.
"Production logs showed water entering the wellbore at a rate of 650 b/d from a section of the gravel pack in the upper lobe of the sand," he said, "with 61% of the gas and all of the water coming from the upper two-thirds of the top perforation set."
A full coiled tubing intervention, using the system, sand and completion fluid, isolated a high-permeability streak in the upper section of the gravel-packed completion, said Warren. Once gelled, the polymer held back water flow, and gas was produced from below the treatment, he added.
"The 96% reduction in the water-to-gas ratio (WGR) greatly exceeded the 50% reduction calculated before the treatment," he said. "With that level of water shut off, the operator was able to return the well to production at a rate of 3.4 MMcf/d."
Total economic value to the customer from the WGR reduction was some US $3.2 million, he said, based on the net present value of the well's production minus the cost of the treatment.
While polymer gels have proved highly successful in specific applications, including shutoff in the near-wellbore matrix of high-permeability formations with zonal isolation, as well as selective fissure shutoff, service companies also are developing low-viscosity polymer systems for low-permeability zones. Halliburton calls its PermSeal. Similarly, companies are developing "smart," or selective, polymers and surfactants called relative permeability modifiers that produce a permanent gel-like material to halt flow from water layers, yet retain fluid behavior in oil layers to allow production to continue.

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