I. Introduction Early in its history, petroleum mining has realized that, like minerals, hydrocarbon products are limited in resources. First mined on easily accessible lands and from shallow depth, now petroleum production has been reaching to the remotest areas and deepest point possible penetrating the crest of this planet we call Earth. All for the race to obtain the most crucial liquid and gas ever influencing the civilizations of human kind.
But on modern times, starting on the 1980s and escalating in the 1990s, the challenge on finding petroleum reserves are not limited to ranges and depths, but also on separating something that is crucial to life but useless in term of petroleum productions: water. Indeed, before the speculators dominate the oil price and inflate it to heavenly level of beyond US$ 100/barrels, there are poor fated oil wells that must be shut down because they have 20-30% of their productions in form of the polar phase. Nowadays, it is common to see water wells with oil as their residual products, but the water is dumped into the sea or water-dumping well and the oil go to tankers and shipped.
But the water itself, although for now is not considered a threatening monster like two decades ago, still create hindrances for oil productions. Water, being less viscous than oil, moves more agile than oil, thus in race to exit the liquid bearing earth layers, water has been to known to be victorious. A phenomenon know as water coning is a source of headaches for many oilfield operators because when the well suffers from water coning, in which water, although coming far below the oil phase and perforations intervals, flow more freely when get sucked by drawdown that exists in the wellbore, dominate the interval perforation, and block the way from oil phase. This is seen as sudden increase in water production and can drastically change the way of the oilfield operations.
Bigger, better separations techniques are required once all of the oil wells in the oilfield get conned up. This needs investments in bigger separators, bigger gas floatation units and the additions of water dumping systems. Not to mention environmental problems and challenge to reduce corrosions to conduit systems.
Many refuse to invest on them, and decide to shut down the wells instead. Many sold their operator licenses to other daring, more capitalized outfits.
And many others choose to change the wellbore and formation properties in order to reduce the influx of water. One of the changes that can be done to the formation properties is changing the wettability of the formations.
Wettability is defined as the preference of a solid to contact one liquid or gas, known as the wetting phase, rather than another. The wetting phase will tend to spread on the solid surface and a porous solid will tend to imbibe the wetting phase, in both cases displacing the non-wetting phase. Rocks can be water-wet, oil-wet or intermediate-wet. The intermediate state between water-wet and oil-wet can be caused by a mixed-wet system, in which some surfaces or grains are water-wet and others are oil-wet, or a neutral-wet system, in which the surfaces are not strongly wet by either water or oil. Both water and oil wet most materials in preference to gas, but gas can wet sulfur, graphite and coal.
Wettability affects relative permeability, electrical properties, nuclear magnetic resonance relaxation times and saturation profiles in the reservoir. The wetting state impacts water flooding and aquifer encroachment into a reservoir.
A naturally water-wet formation could be changed into an oil-wet formation that locks molecules of oil and reduce oil productivity. The change occurred because oil got pushed into the formation rocks by the more mobile and denser water. Flowing water is a polar phase that tends to lock on other polar phase, i.e. water molecules that are there in the formation rocks. The water molecules get pulled out of the rock, and the vacant locales are filled by oil molecules got pushed sideways by the water molecules.
Finding a way to make the formations refuse to be contacted by oil molecules is the Holy Grail every oilfield operators seek. Ways to obtain it have been tried many times, and many of them points to the surface active agents being the type of answers they are seeking.
A surface active agent (= surfactant) is a substance which lowers the surface tension of the medium in which it is dissolved, and/or the interfacial tension with other phases, and, accordingly, is positively adsorbed at the liquid/vapor and/or at other interfaces. The term surfactant is also applied correctly to sparingly soluble substances, which lower the surface tension of a liquid by spreading spontaneously over its surface. Surfactants in solution are often association colloids, that is, they tend to form micelles, meaning aggregates of colloidal dimensions existing in equilibrium with the molecules or ions from which they are formed.
The theory goes like the following. The surfactant will reduce the surface tension of the oil molecules inside the pores spread all over the formations. The hydrophobic ends will then bind the oil molecules while the hydrophilic ends will bind with the water molecules, creating an emulsion that carries the oil and water together outside. This will reduce the amount of oil stuck in the pores and therefore increases the oil production.
Some surfactants/flocculating agents can also bind with solid mineral particles and water at once.
Other type of surfactant is a chemical or combination of chemicals that have demulsifying properties that will separate oil and water which are combined in an emulsion. The demulsifier will create bridges between oil molecules thus will combine them and make them separate from water phase. Demulsifiers usually made from cationic surfactants such as polyacrylamide.
A combination of surfactants and demulsifiers can in theory dig up oil that are stuck in the pores, changing the formation rocks into water wet, and then fill up the vacant locales in the pores with mineral and water binding detergents so that that there will be no oil molecules precipitated in the future.
Finding such a combination is tricky because formations on different wells are unique to each others. Especially in mature/gray oilfield such as Malacca Strait area operated by An Oilfield operator.
An Oilfield operator have been trying to find a fitting cure for reducing the ever increasing water production plaguing its operatorship oilfield area. Besides the obvious zonal isolation procedures, Wettability changing procedures are also been tried with a varying degree of success. This mainly involves surfactant chemicals ranging from oil-based synthetic-surfactant to DNA-based water-based surfactant.
II. Problems
Target field areas have suffered from decline in oil productions since the field is first produced in 1986. The decline has been recognized as the effect caused by the raise in water production. The raise in water production itself is caused by mainly two phenomena: water coning and water leveling.
All the charts above can be used to identify the fact that infill well which are tapping into un-swept oil are not effective in long term in combating oil production decline and water production ascension.
New ways of increasing oil production and tackling water production from rising are needed.
There are methods of re-completing the wells by isolating water producing formations. This method will reduce the total production of water but have tendencies to reduce oil productions because water producing formations usually have minimal oil produced too. This method will mainly reduce the watercut.
A way to reduce watercut and increasing oil productions without resulting in reduction of total fluid productions is needed. One of the ways is by applying surfactant-based stimulations into the formations that will hopefully change the tendencies of the formations from holding back oil to holding back water.
One of the types of surfactants that are applicable are emulsion breakers.
The followings are results Applications and results of Emulsion Breakers CURE on several wells on Target fields.
III.APPLICATIONS AND RESULTS
III.1 W-36
W-36 was the first well stimulated using emulsion breaker. The well was chosen because it has been previously stimulated using emulsion breaker in 2004. The first stimulation was done because the well was suddenly stopped giving liquid and it was identified that the well has severe emulsion and heavy oil. When the production rate of the well was dropped in 2007, it was thought to stimulate the well again using emulsion breaker.
The results of the stimulations were surprising, as water production was reduced and oil production rose sharply.
III.2 W-77
W-77 was a candidate for stimulation using DNA-based relative permeability modifier, but was stimulated using emulsion breaker instead to avoid a workover rig from being standby.
The results of the stimulations were surprising, as water production was reduced and oil production rose sharply.
IIII.3 W-73
W-73 was a well which was stimulated using relative permeability modifier but was not successful. Stimulation using Emulsion Breaker was proposed to optimize the oil production on this well.
The production figure shows increase in oil production while reduction in water production, similar to post-stimulation results for W-36 and W-77.
III.4. Z-01
Z-01, which was located outside Target field, was chosen to be stimulated because it has similar sands to Target wells but with hydrocarbon bearing sands that are slightly deeper. With the same stimulation method and procedure as applied on Target wells, the results are not satisfactory
III.5 W-64
W-64 was a well which had been successfully stimulated using relative permeability modifier and had gained more than 50% profits. Stimulation using emulsion breaker was done to compare this cheaper type of stimulation with the successful rpm stimulation.
The results are better oil production and reductions in watercut level.
III.6 W-66
W-66 is a well that is close and shares similar sand formations with W-66, and haven’t been tried to be stimulated using surfactants. Emulsion breaker is tried on this well to try stimulating the well using relatively cheap stimulation procedures.
The results are not satisfactory as post-stimulation watercut level is erratic and in average is higher than pre-stimulation level.
III.7 W-86
W-86 was chosen as trial well for emulsion breaker stimulation because the well represents the latest infill wells and to try whether the emulsion breaker can be used to stimulate them. Furthermore, W-86 has the history of most erratic watercut level among the wells of Target field.
The results of the stimulation show that the erratic nature of the watercut level of W-86 is still there and was unable to be solved by the stimulation.
III.8 W-45
W-45 was tried to be stimulated using emulsion breaker to test the feasibility of the emulsion breaker to stimulate Target wells that have watercut above 95%. The result of the stimulation shows that stimulation done on W-45 is yet to show any improvements over the pre-stimulation production profile.
III.10 W-81
W-81 has been peculiar well that was unintentionally got stimulated when was undergoing injectivity test that push KCl brine into its formations. Another liquid injection using diesel fuel was successful on reducing watercut level. It was thought that a stimulation using emulsion breaker would yield satisfactory results. The results of stimulation using emulsion breaker that was applied to this well show W-81 oil productivity was increased somewhat and its watercut was drastically reduced
IV. DISCUSSIONS
There is simply no easy rule of thumbs regarding chemical manipulations on hydrocarbon bearing sand formations. The results gained from the stimulations using emulsion breakers discussed here are very much varied on many characteristics.
One shared characteristic of all successful jobs are the fact that the pre-stimulation watercut is below 85%. The exact nature of this phenomenon is not fully understood yet, but it can be said to be connected to the nature of the flows of polar, non-polar, and the interfacial phases. Simulations have been done for wells that have watercut level above 90% and their water-related problems are commonly associated with coning and water up-leveling phenomena than wetting problem. Wells that have watercut levels below 85% can be said to be less suffering from coning problems and having more problems with the wettability of the formations.
Looking at results from W-36, W-64, W-73, and W-77, we can say that water that was produced from those wells was flowing out because the formation tends to block the flow of the oil. By chemically manipulate the formations, they have become less prone to block oil flow and more prone to block water flow. It can be said that the relative permeability of the water have been effectively reduced and that which of oil’s have been increased.
One theory that is briefly mentioned on introduction section is the change of formation wettability. This theory suggests that chemical which has affinity to water and sand-formation minerals on its molecular ends can peel out oil from the formation matrix. After peeling out oil molecules, the chemical will take the spot left by oil by attaching to the formation matrix on one end. Its other end will attract and bind water. If this type of chemical (or chemical system) can be applied effectively, it will drastically change the properties of formation matrix, and in the end, increase oil productivity.
Whether the emulsion breaker stimulations that have been performed on W-36, W-64, W-73, and W-77 act like mentioned on the previous paragraph or not is still to be confirmed, but from the results above, it can be said that the emulsion breaker stimulations are performing like the theory have mentioned. With the same or even lower post-stimulation rates, the watercut is reduced and oil production increases. This is impossible if there is no properties change of the formation matrix.
As for W-66, which has pre-stimulation watercut level below 85%, the cause of its failure still needs to be confirmed. There is one possibility that a packer set to isolate water-producing formations leaked out. This possibility still needs to be confirmed.
W-86 has history of erratic watercut level that indicates there is another problem inherent with the well than formation wettability and if that problem is not solved, the efficiency of the emulsion breaker stimulation is in doubt.
V. CONCLUSION
1. Emulsion Breaker stimulations are effective in wells that still have watercut below 85% and have low possibilities of already suffering from water coning
2. Emulsion Breaker stimulation is a low-cost high yields stimulation that have a high ratio of success if applied to wells that fits the requirements mentioned on conclusion number 1
3. Further confirmations in lab is still needed to ensure the exact nature of emulsion breaker stimulations
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Contributor's Note
For confidentiality, exact data are omitted
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