Over the past 15 years, thousands of producing wells in the Permian Basin, north-central Texas, Midcontinent and Rocky Mountain regions of the United States have been treated with polymer gel to reduce excessive water production. Most of these treatments have been applied to naturally fractured carbonate and sandstone reservoirs where bottom or edge water drive is the primary producing mechanism.

Recently, the same polymer gel technology was successfully used to reduce water and establish commercial oil and gas production to a new well that was drilled in Geauga County,

Figure 1. The graph shows the pressure response and the injection rate used to place a total of nearly 420 bbl of gelant.
Ohio, where a hydraulic fracture stimulation treatment in the target Clinton sandstone propagated out-of-zone into an overlying water-bearing formation. A novel procedure was used to preferentially place the gel into the water zone by bull-heading the treatment through the Clinton perforations. As a result, production was changed from a pre-treatment rate of no oil, no gas and 85 b/d of water, to a sustained post-treatment rate of 22.5 bbl of oil, 20 Mcf of gas and 25 bbl of water a day.

The subject well is located in Geauga County in the northeast corner of Ohio near Cleveland. In this area of Ohio, the Clinton formation is a prolific producing reservoir that was originally deposited in a delta-shelf environment where many bars and channels were formed. Average reservoir porosity is about 9% in these wells, average permeability is very low at 0.1 mD, and no natural fractures are present. The formation, which is encountered at a depth of about 4,100 ft (1,250 m), has gross and net thickness of approximately 200 and 105 ft (61 and 32 m), respectively. Bottomhole temperature is 100°F (38°C) and pressure depletion is the primary producing mechanism.

Hydraulic fracture stimulation treatments, with proppant, are required to establish commercial hydrocarbon production from this low-permeability reservoir. Successful stimulations result in dry oil and gas (i.e., no water) production. Occasionally, however, a stimulation treatment will propagate out-of-zone into other water-bearing formations, and the result will be excessive water with little or no hydrocarbon production. The well described in this report was drilled in October 2004, and the openhole logs indicated that gas “pay” was present in the Clinton. Subsequently, the well was hydraulically fractured in November 2004 with 50,000 lb of sand, and the post-frac flow-back appeared “normal” for the Clinton with a good show of oil and gas. The well was first put on production with artificial lift equipment in March 2005, which was 5 months after the fracture stimulation treatment. The initial producing rate was 85 b/d of water with no oil or gas, and the producing fluid level could not be lowered below a depth of 500 ft (152 m) from surface. Consequently, the well was shut-in June 2005 due to excessive water and no hydrocarbon production.

The operator believed that high pressure observed at the end of the stimulation treatment caused the frac to breach the overlying reservoir seal and propagate into the water-bearing Newburg limestone formation located about 250 ft (76 m) above the top of the Clinton. A produced water analysis confirmed that the source was likely the Newburg. Although it was also believed that only 5% of the frac propagated out-of-zone into the Newburg, it was enough to provide a preferential flow conduit for water into the Clinton perforations. The operator speculated that the 5-month time lag between the completion and activation dates allowed the fracture conduit to become saturated with water.

MARCIT polymer gel technology was selected for use at the well in an attempt to preferentially reduce water production from the Newburg water zone. The gels are created by dissolving dry polyacrylamide in water, and then a chromium III cross-linker is added to initiate the gelation process. The pre-gel or “gelant” solution is injected as a liquid that later turns into a more solid gel-like material with the passing of time. The gels form faster at higher reservoir temperatures. Gel strength is controlled by the polymer concentration; weaker gels are formed with lower polymer concentration and stronger gels are formed with higher polymer concentrations.

The decision was made to bullhead an arbitrary volume of gelant into the existing Clinton perforations so that it could follow the path of least resistance (hydraulic fracture conduit) up and into the Newburg water zone. The hope was that the gelant would flow up the fracture and into the Newburg matrix, so that Newburg permeability would be reduced (damaged) to the point that it would no longer provide for water flow into the fracture. It was also decided that the volume of gel ultimately placed would be dictated by pressure response during the job. We did not believe there would be any advantage to exceeding the reservoir parting pressure while placing the gel, as additional fracturing could exacerbate the problem rather than helping. Therefore, it was agreed that the treatment would be terminated if the injecting pressure approached the reservoir parting pressure as calculated from the frac gradient, which in this case was about 1,000 psi tubing pressure.

Weaker gels were injected first so that they could penetrate the Newburg matrix, and higher
Figure 2. Historical oil, gas and water production for the Clinton formation well shows results of the gel and cleanup steps.
polymer concentration gels were injected at the end of the job to provide for more strength in the higher draw-down pressure area within the fracture. After placing the gel, we wanted to maintain the integrity of the hydraulic fracture so that it could provide for the connectivity between the well bore and the Clinton reservoir as was originally intended, and in order to accomplish this, we believed it would be necessary to displace the gel from most of the hydraulic fracture. Further, we wanted to make sure that the displacing fluid had the ability to break down and remove any residual gelant that may have formed a “cake” on the walls of the hydraulic fracture while the job was being placed.

If allowed to remain, gel “cake” might restrict hydrocarbon flow into the fracture from the adjacent matrix. Therefore, a weak bleach solution was selected for the displacing fluid, and ideally, we wanted to use a bleach volume that would displace the gel from most of the fracture, but stop just short of the place where the fracture intersects the Newburg water zone. In order to know how much bleach would be required to displace the gel to the “tips” of the fracture, we had to estimate the hydraulic fracture volume. To estimate this volume, we assumed that the 50,000 lb of sand proppant used in the fracture stimulation treatment was packed tightly within the fracture, and that the cumulative pore volume between all of the grains of sand should provide a close approximation of the total fracture volume. We calculated that the 50,000 lb of sand used in the frac job has a total pore volume of 29 bbl. Ultimately, we decided that we would displace the gel from two-thirds of the fracture using 20 bbl of bleach solution. The 20 bbl bleach solution was then displaced to the perforations with water. Finally, the well was shut-in for a period of days so that the gels would have plenty of time to reach their final strength and maturity.

When the well was reactivated after the gel treatment in April 2006, it began producing at a stabilized rate of 10 bbl of oil, 5 Mcf of gas and 10 bbl of water per day at maximum draw-down (i.e., “pumping off”). Since water had been successfully reduced by the gel treatment, and hydrocarbon production was restored at commercial rates due to improved draw-down on the reservoir, the operator decided to see if oil and gas production could be further improved by selectively stimulating the Clinton reservoir rock around the perforated area using gas propellant technology. Gas propellant technology creates multiple radial fractures that extend 10 to 50 ft (3 to 15 m) from the well bore with minimal vertical growth.

After the gal propellant stimulation was performed in October 2006, the well began producing at a stabilized rate of 22.5 bbl of oil, 20 Mcf of gas and 25 bbl of water a day at maximum draw-down. Apparently, the selective stimulation was successful at targeting only the Clinton formation and did not reconnect the well bore to the Newburg water zone.

In summary, polymer gel technology can be used to selectively shut off water in wells where hydraulic fracture stimulation treatments propagate out-of-zone into other water-bearing formations. Subsequently, hydrocarbon production can be increased as a result of improving draw-down on the reservoir. In this case, the gels are being exposed to as much as 1,600 psi of differential pressure. Finally, selective stimulation techniques can be used in tandem with polymer gel treatments to economically improve oil and gas recovery.