In the recovery of oil from oil-bearing subsurface formations, it usually is possible to recover only minor portions of the original oil in place by the so-called primary recovery methods which utilize only the natural forces present in the formation. Thus, a variety of supplemental recovery techniques have been employed in order to increase the recovery of oil from subsurface formations. The most widely used supplemental recovery technique is waterflooding which involves the injection of water into an oil-bearing formation. As the water moves through the formation, it acts to displace oil therein to a production system composed of one or more wells through which the oil is recovered. Many waterfloods have gone on for many years in the same formations.
The performance of a waferflood can be affected by the different types of rock in which the oil has been deposited. It is well known that many oil reservoirs are comprised of more than one oil-producing layer. These layers exist at different depths in the formation. Often, oil is produced from several distinct zones (layers) which may or may not be physically situated adjacent to one another in the reservoir. Different oil-producing zones usually consist of rock with different physical properties, and there is no reason to expect that the different oil-producing layers in a particular reservoir should in any way be similar.
One of the most important factors affecting oil production is the ability of the rock comprising the oil-bearing zone or zones to transmit flow under an imposed pressure gradient. The property used to describe the conductivity of a porous solid to fluid flow is called permeability. If fluid flows relatively easily through zone type of rock under a fixed pressure driving force, then that rock is said to have a high permeability. If it is very difficult to force fluid through a type of rock, then that rock has a low permeability.
In a reservoir, the materials comprising the different oil-producing layers usually have different permeabilities. Oil and water will usually flow much more easily through some of the layers than through others, simply because the physical makeup of the rock is different in the various oil-producing zones. If a reservoir containing multiples zones (a layered reservoir) is involved in a waterflood treatment, it is well known that the zones with the higher permeabilities and greater thicknesses will receive more water than the low-permeability or thin zones. Furthermore, once water passes through a zone and pushes some of the oil out, the permeability of that zone to the injected water increases even more. The net effect is that in many cases, the overwhelming majority of the water that is injected throughout the life of a waterflood passes cleanly through the high permeability zones, and very little water enters the low permeability zones. In fact, it is often very difficult to make any appreciable amount of water enter low-permeability zones if there are higher permeability zones in the formation to take the water. Oil originally in place in the high permeability zones is eventually displaced relatively efficiently, while oil trapped in the low permeability zones remains largely unrecovered thereby resulting in relatively poor sweep efficiency of the aqueous flooding agent.
To improve recovery from layered reservoirs, one needs to direct a greater fraction of the injected water into the low permeability zones. Treatments designed to do this alter the flow fractions or flow profile to the different oil-bearing zones and are thus called "profile modification" treatments. Various methods have been to try to alter the distribution of water flow to the various zones. One such method is a polymer gel treatment that has been used with success in certain instances. In this type of treatment, an aqueous polymer solution is crosslinked, or reacted, to form a stable gel. After crosslinking, the gel is injected into the water-injection wells. The gel flows into all of the oil-producing zones, but primarily into the high permeability zones because the resistance to flow into those areas is the lowest. Once in place in the high permeability areas of the reservoir, the polymer undergoes a partial re-gellation in the porespace of the rock. The effect of placing gel in the porespace in this way is to partially plug, or reduce permeability in the high permeability streaks. When water injection is resumed, the water will encounter a greater flow resistance than before in the high permeability zones. In this way water can be redirected into previously unswept (low permeability) zones.
In general, polymer gel treatments for profile modification have a serious drawback which in many cases can cause the treatments to reduce the efficiency of the waterflood instead of increasing it. When the gel is injected, it flows like a liquid. The majority of the gel does flow into the the high permeability area, but some fraction of the gel also flows into the low permeability zones. Gel that enters the low permeability streaks also results in partial plugging of those areas. And because permeability reduction very near the wellbore has a much greater effect on the overall flow profile than does plugging further into the formation, any gel that penetrates significantly into the low permeability zone can negate any beneficial effects of the treatment. Furthermore, gels tend to have a greater permeability reducing effect in rock having a low permeability to begin with. These effects can lead to a situation where even when the majority of the gel enters the high permeability area, the relative permeability reduction in the low permeability zone is greater. That is, the low permeability zones get plugged more than the high permeability zones, and this is the exact opposite of the desired result. When this happens, the net effect of the treatment is to increase rather than decrease the fractional flow of water to the already cleanly-swept high permeability zones.
In some cases, it is possible to use mechanical means to inject the gel only into the high permeability streaks and avoid any gel placement in the low permeability zones. This is done by sealing off those sections of the wellbore where gel placement is not desired, using packers, chokes in injection strings, etc., and injecting only into selected (high permeability) areas. When mechanical diversion can be accomplished, it is a very effective means of treating selected zones. The technique often fails however, because fluid either leaks past the packing devices used to confine injection to a single zone, or because gel flows along the outside of the wellbore from the zone that is to be plugged to nearby low permeability zones. Gel that inadvertently enters the low permeability areas can plug very effectively and the treatment can essentially cause more harm than good. Additional costs are also incurred whenever mechanical packing equipment is used in a well treatment.
Polysaccharide biopolymers, such as xanthan gels, cellulose derivatives, guargum, etc., are useful for permeability profile control in the consolidated gel-forms. Chromium consolidated xanthan gel has been used with success to avoid some of the serious cost and failure problems associated with mechanical zone isolation. The xanthan/chromium gel system has a very attractive properly that causes preferential diversion of the polymer into higher permeability zones without the use of mechanical diversion. This property is called selective penetration. A polymer that exhibits selective penetration will show preferentially in the high permeability streaks when both high and low permeability streaks are present. In this situation, one would normally expect a distribution of flow into various zones in the reservoir depending only on the height of each zone and its permeability. The xanthan/chromium gel, however, tends to flow in greater proportion into the higher permeability streaks than would be expected even when the zone height and permeability are accounted for. The high permeability zones are more effectively plugged and undesirable plugging of the low permeability zones is reduced. When waterflooding is resumed, the result is a net decrease in water flow in the high permeability streaks and better oil displacement in low permeability areas.
Because of its selective penetration characteristic, the xanthan/chromium gel is a very attractive gel for profile modification. A drawback of the xanthan/chromium system is its low temperature stability limit. At temperatures above about 140 degrees Fahrenheit, the xanthan eventually thermally degrades and is useless in diverting water flow. Thus the xanthan/chromium gel cannot be used in reservoirs above 140 degrees. This is a very serious limitation as the majority of reservoir temperatures exceed 140 degrees.
In some types of zone-specific treatments, diverting agents in the form of finely ground solids can be used to direct the flow into the desired zone of a formation. An example is the acid treating of reservoirs to increase the permeability in low permeability zones. Here, the goal is to inject acid only into the low permeability streaks, and finely ground silica flour is sometimes added to the acid for this purpose. The solids flow primarily to the high permeability zone because that is where the majority of the flow goes. The particulates, being too large to enter the rock matrix, form a filter cake on the surface of the high permeability zone. The filter cake provides additional resistance to flow, and the result is a net diversion of fluid to the low permeability zone. The filter cake can be easily removed.
The present invention provides a method wherein a selective gel system, preferably a xanthan/chromium constructed polymer gel system, which exhibits the property of selective penetration for the purpose of profile modification, is used in conjunction with another, solidifiable non-selective material such as a gel, polymer or monomer to make the non-selective material behave selectively. In this way, oil reservoirs above the temperature limit of xanthan/chromium gels can be treated in a selective manner with more temperature stable non-selective gels and without mechanical zone isolation, and low temperature wells which although can be treated with xanthan/chromium gels can in addition be treated with non-selective gels that are more effective plugging agents than xanthan/chromium gels. The present process involves injecting a relatively small volume of a selective gel solution, preferably a xanthan/chromium gel, into the formation at a predetermined pressure to cause the gel to temporarily plug the face of the low permeability zones near the injection well while allowing the gel solution to flow into the relatively high permeability zones. Reasonably promptly thereafter and before the selective gel solution solidifies in the high permeability zones, injection of larger volumes of the solidifiable non-selective material will preferentially enter the high permeability zones and allowed to solidify and plug these zones. Thereafter, the gel plugging the face of the low permeability zones is removed by a flushing agent containing a gel breaker thus allowing subsequently injected flooding fluids to penetrate the oil-rich low permeability zones for the recovering to oil. If used without pre-injecting the selective gel system, the non-selective material would penetrate and reduce permeability in all zones to a comparable degree, and any subsequent flooding fluid injection profile would not be improved. Unlike mechanical isolation techniques, the process of the present invention can be used without the risk of plugging low permeability zones with gel.
USPTO Backgrounds
USPTO Backgrounds