FAQ Page

The process is simply finding and identifying microbes that are living naturally in existing oil fields and “feeding” them a special formula of nutrients that is specifically formulated for the field being treated—basically a specific nutrient “cocktail”. The process causes the microbes to rapidly multiply and increase their metabolism to stimulate the life cycle of the microbes by “amplifying” the natural process. As the life cycle accelerates, the microbe’s cell wall (skin) changes and the organisms change from being hydrophilic (water loving) to hydrophobic (disliking water). When this happens, the microbes move toward the oil and act at the interface between oil-water and oil-rock contact surfaces. The process then allows the formerly trapped oil to break down into unique micro-droplets of oil and to flow more freely within the reservoir rock formation. This is the primary oil release mechanism. A secondary potential benefit is the creation of a mild temporary emulsion (oil, water and microbes) through the agitation of the fluids as they flow through high velocity channels in the porous reservoir. The lightly emulsified fluids form a fluid system that forces water to enter new flow channels, thereby displacing more oil from the reservoir.

In almost all cases, oil reservoirs contain a multitude of naturally occurring microbes as part of a unique subterranean eco-system. The existence of such systems has been the target of much of Titan’s research for more than thirty-years. Titan does not grow or culture microbes to be injected from the surface into the reservoir. We only access microbes that have already adapted to the hostile, underground environment in a natural way. Titan has found oil reservoirs to be a rich biologic environment. Titan targets specific types and species of microbes that can be managed by various nutrient formulations. By managing the biology and ecology of the reservoir in a natural way, the flow characteristics of the otherwise “trapped oil” is allowed to flow more freely toward the producing oil wells. By preferentially treating water injection wells, a large part of the reservoir can be affected in a very positive way to enhance production and oil recovery. 

As the natural microbes attach to the “trapped” oil, the benefit is two-fold. First, the microbes attach to the oil and cause a deformation resulting in the oil being formed into smaller micro-droplets that can flow easily through the reservoir rock matrix. Secondly, the attached microbes concurrently act to reduce interfacial tension between oil and water and between the oil and the rock surfaces. Both mechanisms release the oil and allow it to flow more easily and fluid mobility is positively affected. A third mechanism is the formation of temporary, non-dynamic emulsions to divert injected water to new flow paths to improve the sweep efficiency of the reservoir and produce additional oil resources. 

The oil production increase is dependent on many variables including residual oil saturation, the effectiveness of the existing waterflood process, reservoir thickness, permeability variation, porosity, well spacing and the ability to contact oil and water with the Titan nutrients. In general, fields that have shown good response to waterflood are highly likely to benefit from the Titan Process. Titan treated reservoirs have shown sustained increases of production between 7% to 1000% and we have been successful in reestablishing production in wells that have been “shut-in” due to uneconomic production. Titan has experienced an average oil production rate increase of 92% on 48 oil fields from over 300 well applications.

Depending on the characteristics of the oil field, the cost per incremental barrel produced should be $6 - $15 per barrel. Treatments to date have been lump sum payments per treatment. Initially, water cut generally decreases. Actual individual treatments, when priced on a lump sum basis, vary on the physical characteristic of the oil reservoir in terms of production rate, water injection rate, reservoir thickness and others. Treatments are adjusted by the evaluation of these parameters. Lump sum treatments for individual production wells have generally been in the range of $25,000 to $75,000 per treatment but the cost depends on the reservoir, size of the wells for water flooded fields, the water injection rate and reservoir volume determine costs. Incremental barrels are determined as the post-treatment actual production compared to an established base production forecast agreed between Titan and the field owner.

No. With the Titan Process, the oil quality does not change.

The earlier the Titan Process is applied to a field the greater the potential to mitigate production declines. This applies to wells in primary production or those into which water is injected (waterflooding). However, treating water injection wells is the most effective way of contacting a significant volume of the reservoir and, hence, having a greater impact on the microbial population in the oil reservoir. The Titan Process is not a process just for oil reservoirs nearing the end of their economic life. The earlier the Titan Process is applied the better as it will reduce water-breakthrough, improve the “health” of the reservoir by managing the ecology of the reservoir, improve the effectiveness of the waterflood and lead to a potentially longer life for the field. The optimum time is after the start of a waterflood project—once waterflood performance is defined—perhaps, one to two years after flood initiation. The reservoir management sequence should be: Primary, Waterflood and then the Titan Process®.

Titan has a five-step process as we review a field’s suitability and likelihood of success; 

1. Field screening based on historical and physical field characteristics.

2. Fluid sampling of 2-4 representative wells from the target field and detailed laboratory analysis (this step takes from 6-10 weeks).

3. Treating 2-4 single producing wells with an In-Situ Microbial Response Analysis (ISMRA™). This step is critical to the analysis and forward treatment program. 

4. Conducting a pilot program in one or more water injection wells to monitor the response on adjacent producing wells. Fluids from the production wells are then tested in Titan’s laboratory to document the microbial behavior. 

5. Expansion to a larger pilot or full field application depending on field size.

Waterflood treatments are on a cyclical basis. The frequency is initially three times per year but is dependent on the characteristics of the field and the response in the producing wells affected by the water injection wells. Once the microbial ecology is established, the time between cyclic treatments increases depending on the results of laboratory fluid analysis. The Titan Process is not disruptive to normal field operations and does not require new or permanent facilities to be installed.

We know the process has been very successful in reservoirs from the low twenties and above. We have documented successful treatments from 16ºAPI to 42ºAPI. To date, not enough work has been done in the field with lower API gravity oils to be absolutely definitive on the lower limit. Lower gravity crudes have generally been seen to have fewer communities of microbes available, possible due to geologic heating of the oil. However, some recent testing has given some indication of more active microbial communities in heavy oil reservoirs. Only laboratory analysis can determine if the appropriate microbes are present in sufficient numbers. Titan continues to push the limits of API gravity. In some reservoirs, we have found unexpected microbes to be present due to natural adaptation.

The resident microbes that the Titan Process uses are already surviving in the conditions of the oil reservoir. There is no need for the microbes to adapt to the reservoir conditions since the microbes are not transported from the surface to the reservoir as with other past microbial processes. That being said, microbes cannot generally survive extremely high temperatures. Titan has had successful treatments at 190° F (88°C). At present, this temperature is considered to be at the high-end of the temperature range, but laboratory analysis provides the only definitive answer. Since there is a relationship between reservoir depth and temperature, the current upper limits would indicate a current qualitative treatment depth limitation of between 9000ft and 9500ft. This is a fertile ground for extending the treatment limits since nature has a knack for species adaptation in extreme environments. For Titan, laboratory analysis is the key. 

Offshore water flood operations many times have a cooling effect on BHT and we have found species surviving in offshore reservoirs that were believed to be much hotter than the actual temperature.   In other words, the BHT was cooler than reported.

As with temperature, the Titan Process uses microbes that are already adapted to both pressure and temperature. Tests on reservoir microbes have been carried out at 400 atmospheres (5880 pounds per square inch). 

Within a wide sampling of global reservoirs, salt tends not to be a major problem. 

High Saline can be a problem in the same way that very high temperature can be a problem. We have found that very high salt concentrations tend to decrease the population and concentrations of microbes, but this can only be determined by laboratory analysis. We generally work with reservoirs where salt concentrations are less than 120,000 ppm chlorides. A very large portion of oil reservoirs is in this range. Microbes are sensitive to very high salt concentrations and deviations from neutral acidity/alkalinity.            

Microbes are small. A teaspoon of garden soil can contain One Billion microbes.  In an oil reservoir our nutrients can allow one single microbe via mitosis (the splitting of a cell) to become One Billion microbes within 36hrs. The Titan Process creates a very large number of microbes over a short period of time. When fed the specifically formulated Titan nutrients, the microbes rapidly multiply in number while the food supply lasts. Then as the microbes proceed through their life cycle, their membrane surface is transformed to produce the changes that allow for the benefits and the corresponding improvement in flow characteristics.

No. The nature of their skin keeps them apart and keeps the newly formed micro-oil droplets from re-coalescing into larger droplets. This allows the improved flow character to be maintained.

Yes. You may have seen a drop of water falling on a powdery surface. The water contact becomes coated with the particles and the drop maintains its shape. Microbes cover the surface of oil in the reservoir in much the same way. The microbes change the surface area at the interface and reduce the interfacial tension between oil and water and oil and the rock surfaces.

Reservoir souring is very unlikely. The Titan nutrients are aimed at specific beneficial microbes and not sulfate reducing bacteria (SRB) which are often the source cause of hydrogen sulfide gas (sour gas). Because the beneficial microbes alter the habitat to suit themselves and not the SRBs, the SRB activity is reduced. The result is that the reservoir in the treatment area becomes “sweeter” as the SRBs are crowded out. Stimulated beneficial microbes simply overpower the SRBs. Very large sour reservoirs have significant volumes of hydrogen sulfide already in-place. Very sour wells may present a treating problem but the Titan Process will not aggravate the problem.

Near wellbore biocide treatments will not have a significant effect on treatments. Large scale or continuous biocide treatments would need to be evaluated and the effect would be dependent on the type and concentration of the biocide. The process has been used effectively where field biocides have been used on a periodic basis. Titan’s technical and scientific team will review the use of biocides as a part of the pretreatment analysis. 

No. Gas is not a product of the Titan Process—unlike some other past and now defunct microbial processes.  

Yes, as long as we can cause the microbes in the reservoir to be contacted by the nutrient mixture, the effect will be positive. Waterflood operations are the easiest method to introduce the nutrients to the reservoir. The Titan Process nutrients are simply added into the injection water stream. To do this, no capital equipment is needed and the Titan Process gets to work right away. In a natural water drive, the benefit will be dependent on the movement and flow of the natural drive (generally from aquifer behavior). It may be possible to introduce the nutrients through a “watered-out” producer, but additional (or new) pumping equipment may be required. Natural water drives have not been tested sufficiently to make a definitive statement, but there is certainly promise for a successful treatment.

The water cut often decreases as a result of increased oil production. As the freed oil moves toward the producers, the producing wells will show a decrease in water cut with an associated increase in oil production. The timing is dependent on the “transit time” between injectors and producers. We have seen this time-lag generally take from two weeks to six months, but this is entirely dependent on reservoir flow characteristics and volumetrics. 

No. Field operators have not noted any treating or processing difficulties following treatment by the Titan Process. We rarely see any emulsion at the treating facilities and, if such an emulsion should occur, it breaks quickly with normal residence time and heat. However, this has not been noted as a problem in Titan’s treatment history.