Oil well stimulation improved

A new acidizing process focuses treatment on the hydrocarbon-bearing zones, yielding substantially improved results in sandstone reservoirs.

An interview with John L. Gidley, PhD.

A new technique for acidizing sandstones involves pumping a pad of CO2 and solvent ahead of the acid to displace the resident crude. Acid that follows easily displaces the CO2, the path of least resistance, and concentrates its action on damage in the oil zone. The result is more complete removal of damage and more effective stimulation. A side benefit is the reduction in water stimulation which occurs in many conventional acid treatments. E&P spoke with John Gidley of Gidley & Associates about the success of the technique, which has been applied more than 60 times.

E&P: Acidizing has been declining for the past decade, especially in offshore areas. What do you have that will change that?

Gidley: Conventional acidizing, despite many purported improvements, has declined from its level of use in the 1990s. Several reasons account for this decline: inadequate damage removal, preferential water stimulation and problems processing spent acid returns from the treatment.

Some of these result from inadequate design or inappropriate implementation, but a substantial part is inherent in conventional acidizing. Our process deals with these problems and is a substantial improvement over conventional acidizing.

E&P: What do you consider "conventional" acidizing?

Gidley: I use the term conventional acidizing to describe those sandstone acidizing processes that employ mud acid but do not precondition the formation, i.e., displace crude oil from the zone to be contacted with mud acid.

E&P: How is that important?

Gidley: Mud acid (i.e., acid that contains hydrofluoric acid, HF) reacts with sandstone to dissolve clays and feldspars, the materials that are most often related to formation damage. But as HF spends, the dissolved material is precipitated. Overall, the process is one of removing damage by dissolving HF-soluble materials, then re-damaging the formation as the dissolved material is precipitated. If the precipitate is not allowed to contact crude oil in the formation, very little damage is done. It is the interaction of spent-acid precipitates with crude oil that is the source of damage occurring during the treatment. People doing research on sandstone acidizing are generally aware of the precipitation that takes place when HF is spent. But for some reason they have not fully appreciated the problems caused by the interaction of precipitates with reservoir fluids. The common approach is to reduce precipitation by reducing HF concentration in the mud acid. That often provides some improvement, but the problem is not just the precipitates. Rather, it is what happens to the precipitates when they contact reservoir fluids in the formation.

Initially, the precipitated material is an extremely fine, colloidal material that can move through the formation without difficulty. By itself, it is seldom more than a minor nuisance. The problem occurs when it comes in contact with crude oil, and high molecular weight components from the crude oil adsorb on the precipitated material. This alters its wettability, and sets in motion steps leading to the formation of emulsions or sludges. The resulting material often has a severely detrimental effect on the permeability of the formation and may eliminate most if not all of the improvement initially accomplished by dissolving the damaging materials.

E&P: How does your approach differ?

Gidley: Our approach is to take steps that will prevent contact between spent acid products and crude oil in the formation. This means completely displacing crude oil from the zone to be contacted with mud acid. This requires a miscible displacement of crude oil with a soluble gas, CO2, and a solvent, usually xylene, to achieve dynamic miscibility. CO2 is especially valuable in this process, not only because of its solubility in crude oil, but also because it is relatively inexpensive, non-toxic except in unusual circumstances, and readily available. CO2 also prevents the preferential stimulation of water.

E&P: You've told me that eliminating contact between spent acid and crude oil avoids the development of emulsions and sludges. You've said that CO2 serves usefully to displace crude oil. You also say that it in some way the use of CO2 eliminates the preferential stimulation of water. How do you know this?

Gidley: Let me deal briefly with the field results. More than 60 treatments have been conducted to date, and to the best of my knowledge only three failures have resulted. All three can be traced to incorrect design or faulty execution in the field. Despite that, a 5% failure rate for CO2-acidizing compares with a failure rate of roughly 35% for conventional mud acid treatments, and those figures give no recognition to the increased damage removal, higher well productivities and the near elimination of preferential water stimulation obtained with the CO2-acidizing process.

Elimination of emulsions and sludges is evident in the ease with which the spent acid returns are processed by emulsion separation facilities. In many cases no change in processing conditions is required. Spent acid returns are demulsified with the same treatment given to concurrent crude oil production from unstimulated wells. The elimination of emulsions and sludges is deduced from these results.

The effectiveness of the CO2-solvent system for displacing crude oil is mainly inferred from the unchanged water cut on the stimulated wells when the system has been implemented correctly.

E&P: How does the use of CO2 to displace crude oil from around the well bore bring about all of these improvements in sandstone acidizing?

Gidley: Let me digress momentarily by pointing out some work that we did at Exxon shortly before my retirement. We did a detailed study of our stimulation experience to see how we might improve it. Among our findings (SPE 14164) was that gas wells were easier to stimulate than oil wells. That seemed odd to me at the time. No one had ever suggested that there could be or should be a difference in the effectiveness of mud acid in stimulating gas wells versus oil wells. Both oil and gas are found in the same kinds of formations, how could their stimulation with mud acid be different? It was truly puzzling, but the results on some 529 wells were very convincing. At the time, we couldn't see how that discovery would help us improve oil well stimulation.

Several years later, it dawned on me that to make oil wells as responsive to the treatment as gas wells, we needed to make an oil well look like a gas well when we acidized it. This suggested displacing oil from the region to be contacted by acid with gas so that any interaction between crude oil and spent acid could be eliminated and the acid reaction would take place in a gaseous atmosphere. As discussed, the gas most useful for this purpose appeared to be CO2.

We subsequently pursued this train of thought, set up a research project to evaluate the idea, and got industry support through several major companies to field test it. Those field tests, in an offshore area that had been poorly served by conventional acidizing, demonstrated the superiority of the method. That work is documented in our first SPE publication on this process in 1996. Additionally, we found that when we had effectively displaced the oil from around the well bore we stimulated oil production without changing the water cut. That was a complete surprise. But it was one of our most valuable findings.

E&P: But why does displacing the crude oil with CO2 help eliminate the preferential stimulation of water?

Gidley: Consider the condition of a well at the time it is pulled off production to be acidized. Generally it has been producing oil up until the time it is shut in for stimulation. At this point, oil saturation in the producing formation near the well bore should be at its maximum. At the same time, the relative permeability to water or to an aqueous phase such as mud acid is near its minimum. As an example, a water-wet sandstone at its maximum oil saturation may have an aqueous phase relative permeability of 1% or less of the absolute permeability. Thus, the producing zone with its high oil saturation is very resistive to penetration by aqueous fluids.

As it enters the formation, acid will follow the path of least resistance. If there is no physical barrier, such as a shale break, to confine the acid to the producing zone, it may under ride the oil zone and head for the water. From that point on, pumping more acid into the formation increases the conductivity of the path to the water zone. When production is restored, water production is increased more than oil.

How does a gas displacement with CO2 change this process? When CO2 is injected into the oil zone, it fingers through the oil because of its low viscosity and unfavorable mobility ratio. But because CO2 is soluble in oil, it is absorbed by oil, reduces its viscosity, increases its volume, and makes displacement of the oil easier. If enough CO2 and solvent are injected, crude oil can be swept cleanly from the zone around the well bore. Some CO2 may be lost to the zones above or below the oil producing zone, but the permeability of the paths to these zones will not be increased since CO2 is largely non-reactive with sandstones.

When acid is injected into the oil zone, it readily displaces CO2 occupying that zone since this is the path of least resistance. By this means, action of the CO2 is concentrated on the oil zone where it was desired in the first place. In the displacement, CO2 serves as an internal diverting agent facilitating flow to the oil zone without stimulating flow to either the gas zone or the water zone. This diversionary effect greatly improves the effectiveness of the treatment both in removing damage in the oil zone and in preventing the preferential stimulation of water.

E&P: It's still not clear why gas wells are easier to stimulate than oil wells.

Gidley: As mentioned earlier, when the HF component of the acid is spent and siliceous material precipitates, the damage is not done until the precipitated material interacts with reservoir fluids. In the case of gas wells, these fluids are primarily low molecular weight hydrocarbons, such as methane, ethane, propane, butane, and gaseous materials such as CO2 and nitrogen. None of these adsorb on the precipitating material enough to change its wettability. Hence, they don't facilitate the development of emulsions or sludges.

With oil wells, the environment within the reservoir is greatly different. The higher molecular weight materials have a greater tendency to adsorb on the newly created silica surfaces and to alter their wettability from water wet to oil wet or to an intermediate wettability. Such a change greatly favors the stabilization of emulsions by the minute partially oil-wet precipitates. Also, mixing spent acid with crude oil may cause the formation of sludges. Both of these processes redamage the formation, reduce the permeability of the productive zone, and impede hydrocarbon production.

In summary, the difference between oil well and gas well stimulation with mud acid relates not to the differences in reservoir rock, but to differences in reservoir fluids, and to their interaction with the precipitating siliceous material. With oil wells, that interaction is strongly detrimental and it redamages the formation.

E&P: You have asserted that CO2-acidizing is more effective in removing damage than is conventional acidizing. Why?

Gidley: Let's recognize at the outset that evaluating the effectiveness in the field of a new acidizing process is more art than science. The problem is that no two wells are exactly alike and any comparative conclusions are subject to the concern that the results are more reflective of well differences rather than differences in the process being evaluated.

To minimize this concern, our approach is to start with two wells in the same field, preferably within the same reservoir. The wells to be compared should be damaged to essentially the same extent before the acid treatment. The skin factor serves as an unbiased measurement of damage for this purpose. We also keep an eye on the increased production following the treatment and the sustainability of that production over time.

While it is difficult to meet these requirements, one area where we were able to find wells in the same field treated both conventionally and with the CO2-acidizing process was in the Main Pass field, in the Gulf of Mexico, offshore Louisiana. We found wells there that before being conventionally acidized had skin factors of 168 and 170.

We were able to compare their performance with that of a well in this same field that had a skin factor of 165 that was subsequently stimulated with the CO2-acidizing process. The results with respect to the skin factors and production rates are a little more involved and that's why I have resorted to the accompanying table. Note that the wells with skin factors of 168 and 170 had skin factors after conventional acid treatments of 50 and 114 respectively. The well stimulated with the CO2-acid treatment had a skin factor of 165 before treatment and five afterwards.

In production terms, the two conventional treatments essentially doubled production in each case while the well treated with the CO2-acid treatment increased production rate more than six fold.
Although the skin factors are seldom available to permit enough comparisons of this type to make a statistical case to evaluate the effectiveness of the treatment, the results just cited illustrate the type of differences often found. In some areas, the CO2-acidizing process has provided successfully stimulated wells where conventional acidizing has been largely a failure.

E&P: Finally, how does the treatment compare in cost with conventional acidizing?

Gidley: The additional materials required add to the cost, but there are compensating factors that permit savings. I prefer to look at the question in a different manner.

The real concern should be how to develop additional oil production at minimum cost per incremental barrel of stimulated production. Because of its greater efficiency in removing damage and in preventing further damage by the treatment itself, the CO2-acid treatment will almost always provide the lowest cost per incremental barrel of increased production. In addition, the reduction in water stimulation may reduce operating costs substantially, and the near elimination of emulsion facility upsets in processing spent acid returns is an additional saving.

In summary, CO2-acidizing should provide more effective damage removal, cheaper incremental production, and better return on investment than conventional acidizing in sandstone formations.