Wednesday, May 23, 2018

Pushing Out the Oil with Conformance Control

The growing problem of water production and a stricter environmental enforcement on water disposal are forcing oil companies to reconsider conformance control - the manipulation of a reservoir's external fluid drive to push out more oil and less water. The technical challenges range from polymer chemistry to detailed knowledge of reservoir behavior. 

By late 1984, after several years' research, Marathon Oil Company laboratories in Littleton , Colorado, USA established a new polymer-gel system to block high-permeability channels within a reservoir and improve oil recovery. Previous attempts using less sophisticated chemistry had failed because the chemicals had become unstable at reservoir conditions and also were partially toxic. During the next three years, Marathon performed 29 treatments with the new system in nine of its fields in Wyoming's Big Horn basin. Fourteen treatments were in carbonate formations, and 15 were in sandstones.

The greatest success occured when injection wells were treated. The Big Horn reservoirs are known to be naturally fractured and the injected polymer-gel system most likely filled much of the fracture system between injector and neighboring producer.  This would force subsequent water drive to enter the matrix rock or fractures untouched by the treatment and push out oil. In many cases, a declining production in the neighboring producer was dramatically reversed, staying that way for several years.

Overall, the 29 treatments yielded 3.7 million barrels more oil than if the treatment had never been done, at a total cost of just $0.34 per barrel. Considering the price of oil at the time ranged from $30 to $24, Marathon had got themselves some very inexpensive production and a clear signal that the age of conformace control had begun

What is Conformance Control?

In the context of a reservoir produced with some kind of external fluid drive, conformance describes the extent to which the drive uniformly sweeps the hydrocarbon toward the producing wells. A perfectly conforming drive provides a uniform sweep across the entire reservoir; an imperfectly conforming drive leaves unswept pockets of hydrocarbon. Conformance control describes any technique that brings the drive closer to the perfectly conforming condition- in other words, any technique that somehow encourages the drive mechanism to mobilize rather than avoid those hard-to-move pockets of unswept oil and gas.

In the pantheon of techniques to improve oil recovery, conformance control is relatively unambitious, its goal being simply to improve macroscopic sweep efficiency. Most enhanced oil recovery (EOR) techniques, for example, also strive to improve microscopic displacement efficiency using a variety of surfactants and other chemicals to prize away hydrocarbon stuck to the rock surface. Conformance control is also less expensive than most EOR techniques because the treatments are better targeted and logistically far smaller.

Another factor also favors conformance control. By redistributing a waterdrive so it sweeps the reservoir evenly, water cut is often dramatically reduced. For many mature reservoirs, treatment and disposal of produced water dominate production costs, so less water is good. Environmental regulations also push oil companies to reduce water production. In the North Sea, residual oil in produced water dumped into the ocean is restricted to 40 ppm, an upper limit increasingly under pressure from the european community. 

Conformance control during waterflooding covers any technique designed to reduce water production and redistribute waterdrive, either near the wellbore or deep in the reservoir. Near the wellbore, these techniques include unsophisticated expedients such as setting a bridge plug to isolate part of a well, dumping sand or cement in a well to shut off the bottom perforations, and cement squeezing to correct channeling and fill near-well fractures. Deep in the reservoir, water diversion needs chemical treatment.

Initially, straight injection of polymer was tried but proved uneconomical because of the large volumes required to alter reservoir behavior and because polymers tend to get washed out. The current trend is gels, which if correctly placed can do the job more efficiently with much smaller volumes. In the future, potentially less expensive foams including foamed gel may be tried. Ultimately, reducing water production may require a new well. The choice of technique or combination techniques depends crucially on the reservoir and its production history.

Take, for example , the caase of two producing zones separated by an impermeable shale, in which the bottom zone has watered out. The first solution is to cement in the bottom zone. Suppose, though, that the shale barrier does not extend to the producing well. Then success with the cement plug becomes short-lived and water soon starts coning toward the top interval.  The only recourse now is to inject a permeability blocker- some kind of gelling system- deep into the lower zone. The trick is not letting the gelling system invade the upper zone. This can be achieved by pumping through coiled tubing to the top of watered-out zone while simultaneously pumping an inert fluid, water or diesel fuel through the annulus into the upper zone to prevent upward migration of the gelling system. 

Deep gelling systems are also the answer for a high-permeability but watered-out formation sandwiched between two lower permeability formations.  A casing patch or cement squeeze may halt water production momentarily, but long-term shutoff requires a deeper block. The fractured reservoir is a variant of this scenario. If natural fractures are interconected, they can provide a ready conduit for water breakthrough, leaving oil in the matrix trapped and unproducible. The solution is to inject and fill the fractures with a gelling system, that once gelled, forces injection water into the matrix to drive the oil out. 

 BP Exploration and ARCO are currently testing a system comprising PHPA and an aluminum-based cross-linker that is hoped will reach deep in the matrix reservoir of the Kuparuk field in Northern Alaska. The cross-linker is another metal-carboxylate complex, aluminum citrate. But unlike chromium acetate, this links the PHPA in two distinct temperature-controlled stages.In the first stages which occurs rapidly in cold water, each aluminum citrate molecule bonds to just one polymer carboxylate site. In the second stage, which occurs only above 50 degree celcius, the aluminum citrate complex can attach to a second carboxylate group thereby cross-linking two polymer molecules and contributing to produce a gel network. Because the cross-link itself contains carboxylate groups and these have an affinity for water molecules, the formed gel may flow in a beaker, yet provide an adequate permeability block in porous rock.

BP and ARCO's strategy is to pump the system into the reservoir through injection wells, where the cooler temperature of the injection water will promote only the first stage reaction, resulting in a pumpable fluid of low viscosity. Then, as the fluid permeates deep into high-permeability sections of the reservoir and experiences higher temperatures, the second-stage will kick in and enough of a gel will form to divert water-drive to less permeable zones.

  An alternative gelling system that guarantees injectability into matrix rock uses simple inorganic chemicals that have flowing properties nearly identical to those of water. Inorganic gels were discovered in the 1920s and are used to this day for plugging lost circulation, zone squeezing and consolidating weak formations. Their failing for conformance control has been a very rapid gelation time, but recent innovations using aluminum rather than silicon have resolved this problem.

 Besides their inherent ability to deeply permeate matrix rock, inorganic gels have another advantage over their polymer-based cousins. If the treatment fluid gets incorrectly placed causing a deterioration in reservoir performance, inorganic gel can be removed with acid. Of course, the acid has to be able to reach the gel to be able to remove it. Polymer gels, on the other hand, cannot be dismantled easily and are therefore usually in place for the duration. 

 If deep penetration in matrix is one key factor in the conformance control debate, another concern is contamination of the gelling system through contact with ions in the formation water. As noted, the DGS system may be adversely affected by divalent anions. PHPA, on the other hand, both before and after gelling may be affected by divalent cations such as Ca2+, which are relatively ubiquitous in formation waters. 

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