In any relationship where both parties are mutually benefited and satisfied, effective listening is paramount. This is true for marriages, friendships, business associates and for national diplomacy. And, it is just as true for oil producing reservoirs - yes, your reservoir can talk and we should listen to it if we do not want to be disappointed with unrealistic expectations created by deaf assumptions.

We are constantly reminded of the power operators gain by listening to the reservoir as its life cycle progresses from the early stages of flood development through depletion maturity. Here, at TIORCO, we have seen the difference listening makes over and over during our past 25 years of service to dozens of operators of secondary recovery projects.

Monitor! Monitor! Monitor! Waterflood response on both the injection and production sides must receive continuous scrutiny by the operator’s engineers and I.O.R. service company to understand what the reservoir is really saying. Only then can decisions and implementation of operational and process design changes work to maintain optimum production performance.

A recent waterflood project located in Wyoming’s Powder River Basin reinforces the requirement for committed long-term monitoring and methodical evaluation of flood performance. The Ash Unit is a small, three-well field producing from the Minnelusa sandstone formation. It exhibits all the characteristic traits of a Minnelusa; extreme permeability variation between 5 to 2750 md with a Dykstra-Parsons coefficient of 0.75 and high oil viscosity giving an adverse mobility ratio over 20. Water injection commenced in December, 1992, along with implementation of a polymer I.O.R. process intended to correct mobility and provide resistance of flow into the high permeability rock.

Initially, TIORCO was not the operator’s I.O.R. service company; however, like dozens of projects before, we had taken the initiative to review the development reports and apply our knowledge base of over three dozen Minnelusa I.O.R. projects in an engineered proposal. So, we were familiar with the reservoir and after waterflood start-up, we maintained contact with the operating engineers and kept informed. We listened to the reservoir.

Oil response came seven months after water injection, but water breakthrough followed right behind only five months later with oil rapidly declining at a 60% annual rate. Then, as if to say, “Now, will you listen to me!”, polymer breakthrough occurred three months after water showed up. The original I.O.R. program used a colloidal dispersion gel (CDG) system created with a high molecular weight anionic polyacrylamide and an aluminum cross-link agent. Injection of the first 200,000 BBL was on a surface vacuum, so the cross-link concentration was increased in four stages over seven months in an effort to produce a stronger CDG that would in turn provide better drive fluid diversion. Surface injection pressure started a gradual, but encouraging increase after the 200,000 cumulative BWI to 850 psig, recorded the same month as polymer breakthrough.

Still plagued with polymer at the producer, declining oil and increasing WOR, the operator ordered a thorough engineering evaluation of the project. TIORCO answered the call and dedicated the engineering staff necessary to listen and evaluate. Analysis of the produced water showed a polymer concentration of 500 ppm - only 250 ppm less than was being injected! Further laboratory investigation revealed that the polymer would only form weak colloidal dispersion gels if the cross-link agent concentration was 750 ppm or lower. Thus, for two years, cross-linking did not occur and the only benefit subscribed to polymer injection was mobility control.

Furthermore, the engineering investigation revealed that increasing fluid levels (i.e. hydrostatic pressure) at the offset producer mirrored the injection pressure build-up and was the responsible culprit for pressure increase, not in-depth fluid diversion hoped for from the CDG. Sweep inefficiency and channeling tendencies were obviously more severe than first thought.

Based on the TIORCO evaluation, the injection rate was reduced to lower the fluid level at the offset producer to achieve a pumped-off condition. A new pre-qualified polymer that produced colloidal dispersion gels at a lower polymer concentration replaced the original supplier. Fluid level fell 3,000 feet and the Hall slope started indicating resistance to flow through the higher perm channels. Consequently, production evaluations clearly showed a shallowing oil decline and a leveling WOR trend. Six months after implementing the I.O.R. process and operational changes, the concentration of produced original uncross-linked polymer and a chemical tracer test indicated that the offending thief channel was too extreme for the mobile CDG system to shut-down.

Thus, a defined volume, bulk polymer gel treatment was designed to invade the high perm channel and shut-off subsequent flow through the watered out zone. The MARCIT-CT^SM gel was placed through the injection well in January, 1995, and resulted in the desired higher injection pressure, an indication of diversion into tighter oil bearing rock. CDG injection continued for three months followed by the present straight water injection.

Patient listening to this heterogeneous reservoir allowed informed decisions that solved significant operating maladies, resulting in increasing waterflood oil production, lowering the WOR and curtailing the disruptive polymer production at the offset. Including the cost for the initial polymer stage with the cross-linking problem, incremental oil has been produced for less than $2.00 per IBO and is projected to ultimately exceed 13.8% OOIP. Interestingly, the most dramatic response to the final I.O.R. program occurred 18 months after placement of the injection conformance correcting bulk gel.

So, along with the operator, we continue to listen and monitor.