Faced with an increase in the need for oil globally, energy companies have two choices: First, they can discover new fields; the second choice is to find a way to increase production for their current fields. Generally speaking, this second option is called EOR, or Enhanced Oil Recovery (it may also be referred to as Increased Oil Recovery or IOR). EOR can recover 30-60% of a site’s oil, as opposed to 20-40% using primary or secondary recovery, as stated by George Douglas Hobson in his “Introduction to Petroleum Geology.” This article will discuss the history of Enhanced Oil Recovery, several methods of recovery that fall under the broad definition of Enhanced Oil Recovery. It will also point out the current use of these methods in Egypt.
Enhanced Oil Recovery has been with us for about 300 years. It is thought that the first EOR was simply a mistake with very positive consequences. Many of the early oil production projects in the USA were in Pennsylvania in the early 19th Century. The technology used was primitive, the workers were not particularly well trained, wells were often abandoned improperly, and surface water entered the productive sand zone, according to J.A. Taber of the New Mexico Petroleum Recovery Research Center. Without foresight, operators believed that the water entering the sands would ruin or “drown” the oil fields. It got to the point to where some states passed laws prohibiting injecting water into oil-producing sands. Over time however, many people with the industry noticed increased production from water flooding and it was common belief by the 1940’s that “unquestionably the most efficient method ever derived for increasing oil recovery,” according to Dr. Grom Heron, Senior Vice President and Chief Technology Officer at Terra Therm.
The first purposeful water flood for oil recovery was in Sweden in the 1740’s, according to Taber. Running water was used to produce crude oil from galleries cut into the rocks bearing strata of “tar and sand.” Even though water flooding was thought to be very effective by more and more people in the oil industry as time went on, it was noticed that the technique only harvested part of the oil. A patent was taken in 1917 for the addition of alkali to the flooding water. By the 1920’s, discussions and studies were happening that discussed how the surface forces, which were responsible for holding the oil in the rock, might be altered to improve recovery. The quest for EOR in the modern age had begun.
The most popular method of EOR, according to Mark Walsh of Texas A&M University and Larry Lake of Rice University in “A Generalized Approach to Primary Hydrocarbon Recovery,” is Miscible Flooding, otherwise known as Gas Injection. This is a general term for any process that introduces gas into the reservoir. The gasses most commonly used in this process are CO2, natural gas, or nitrogen. Gas displacement maintains the pressure of the reservoir and improves oil displacement because the tension between oil and water is reduced. This tension is called interfacial tension because it refers to the interface between two interacting fluids, allowing for total displacement efficiency. Of the three gasses, CO2 is used the most due to the fact that it is the cheapest of the three and it reduces the viscosity of the oil. The displacement of the oil relies on the phase behavior of the mixtures of the CO2 and the crude, which depend strongly on reservoir temperature, pressure, and crude oil composition.
Tut field is a prime candidate for miscible flooding. It is on the Khalda concession in the northern part of the Western Desert. After a thorough investigation of Tut and surrounding locations, it was determined that miscible flooding was the proper method for two reasons: one, the inexpensive availability of CO2 in the area; second, miscibility could be achieved under the current reservoir conditions. It is predicted that 10% of the well’s total capacity could be recovered, oil that would otherwise never be made available, wrote Mahmoud Abu El-Ela of Cairo University for Oil and Gas Journal.
Of course, there are problems with implementing this method generally. It can cause the corrosion of some infrastructure. Increased capital expansion is needed for expenses involved in modifying existing infrastructure. Capital and operating expenses are also needed for the construction and operation of a CO2 pipeline network. There is also a degree of uncertainty surrounding the legal framework of CO2 underground storage. There is also a need for co-operation between CO2 source companies and oil producers, according Oil and Gas Journal.
Plasma-Pulse is the newest technique of EOR. It was developed in the Russian Federation and is currently being used in Russia, Europe, and the USA. In a study done by the Organization for Economic Growth and Development, 90% of the wells using this technology are seeing positive results. The process is clean, safe, and does not harm underground equipment. It utilizes low-energy emissions to create the same effect that many other technologies can produce without the negative impact on the environment, as reported by the Clean Air Task Force. In most cases the volume of oil retrieved with the water is actually reduced from the pre-EOR treatment, not increased. Companies widely ranging as Lukail, Gazprom, and Conoco Phillips use this technology. It is based on technology used in the Russian space program and is being advanced for use in horizontal oil wells.
Currently, due to patent rights issues, the fact that this is a relatively new technology, as well as other concerns, there are no current Plasma Pulse projects occurring in Egypt at this time.
The miscible process is improved by the injection of various chemicals, most often in diluted solutions. They tend to aid mobility and to reduce surface tension. Where the oil has naturally occurring organic acids, injection of alkaline or caustic solutions may lower the interfacial tension enough to cause an increase in production. In some formations an increase in oil recovered can be provided by an injection of dilute solution of a water soluble polymer to increase viscosity of injected water. Dilute solutions of surficants, such as petroleum sulfanates or bio surficants, such as rhamnolipids may be injected to lower the interfacial tension or capillary porusness that impedes the oil droplets from running through a reservoir. Microemulsions, which are special formations of oil, water, and surficant, are very effective in doing this, as stated by Dr. Aurel Carcoana of the Petroleum, Gas, and Geological Science Institute of Bucharest, writing in Applied Enhanced Oil Recovery. Using this technology is limited by the cost of the chemicals as well as their absorption and loss into the rock. In all of these methods, the chemicals are injected into several wells with the production occurring in several nearby wells.
Polymer flooding is a way of increasing injected water viscosity by mixing it with long chain polymer molecules. Doing this improves the vertical and areal sweep efficiency. This is due to the oil/water mobility ratio. The polymer also reduces the contrasts in permeability by plugging high permeability zones flooded by polymers, thus forcing the water to flood the lower permeability zones, increasing sweep efficiency.
Polymers and surfactants can be used together, decreasing the surface tension between oil and water, reducing the residual oil saturation and improving the microscopic efficiency of the process. Primary surfactants usually have co-surfactants, also known as activity boosters. They are co-solvents added to improve stability of the formulation. Caustic flooding is the addition of sodium hydroxide to the injection water. It reduces surface tension, reduces moisture in the rock, emulsification of the oil, mobilization of the oil, and helps in drawing the oil out of the rock, as stated in Chemical Engineering News.
Microbal Injection is part of a process called Microbal Enhanced Oil Recovery. It is not used often because of the high cost as well as a lack of acceptance in the energy industry. The injected microbes either partially digest long hydrocarbon molecules, generating biosurfactants, or emit carbon dioxide. It then functions the same way as the above-mentioned Gas Injection.
The main approaches to Microbal Injection are as follows. In the first, bacterial cultures are mixed with a carbohydrate, (molasses is commonly used) and is injected into the field. In the second approach, nutrients are injected into the ground to nurture existing microbes. The nutrients cause the bacteria to make more of the natural surfactants normally used to metabolize underground crude oil. After the injected nutrients are consumed the exteriors of the microbes become hydrophilic, then they migrate to the water-oil interface area, where they cause oil droplets to form from the larger oil mass, making the droplets more likely to migrate to the wellhead as reported by S.J. Launt Nelson in Oil and Gas Journal.
In a study done by M.H. Sayyouh, M.S., A.I. Blehed, and A.M. Hemeida of the Department of Petroleum Engineering, College of Engineering, and King Saud University, it was shown that Saudi Arabia, Iraq, and Egypt are the three leading Middle Eastern candidates for Microbal Injection. This was due to reservoir rock permeability, oil viscosity and density, and the shallow depth of the wells (2,000-6,000 feet).
Carbon Dioxide is very effective in reservoirs deeper than 2000 ft., where the CO2 will be in a supercritical state, writes Michael J. Austell in “CO2 for Enhanced Oil Recovery Needs – Enhanced Fiscal Incentives.” In high-pressure applications with lighter oils, CO2 is miscible with the oil, which results in the swelling of the oil, a reduction in viscosity, and also causing the possibility of a reduced surface tension with the reservoir rock. With heavy oils or low-pressure reservoirs, CO2 will form an immiscible fluid, or only partially mix with the oil. Some oil swelling may occur, and oil viscosity may still be reduced significantly.
In these applications, between one-half and two-thirds of the injected CO2 returns with the produced oil and is usually re-injected into the reservoir in order to reduce operating costs. The rest is trapped in the oil reservoir. Carbon Dioxide has the advantage of being a much more economical solvent than other miscible fluids, such as aspropane and butane, according to in Chemical Engineering News.
Hydrocarbon Displacement is the process by which a slug of hydrocarbon gas is pushed into the reservoir in order to form a miscible phase at high pressure. A large disadvantage to this however is the hydrocarbon having a poor mobility ratio, and the solvent’s ability to dissolve the oil reduces as it goes through. As with the above-mentioned methods, states M. Baviere in Basic Concepts in Oil Recovery Processes, this is only attempted when it is considered cost-effective.
The next procedures are grouped under the heading of Thermal Flooding. They are various methods that are used to heat the crude oil in the rock formation to reduce its viscosity and/or vaporize part of the oil, reducing its mobility ratio. Heat reduces the surface tension and increases permeability. The oil may vaporize and then condense, forming an improved oil product. These methods include cyclic steam injection, steam flooding, combustion, and solar thermal enhanced oil recovery. Thermal Flooding began to be used in a widespread capacity in the late 1960s, according to Aurel Carcoana in “Applied Enhanced Oil Recovery.”
Thermal flooding is the best method for recovering heavy, viscous oil, while chemical methods are best for low to medium viscosity petroleum. It is good for use in shallow wells and unless used, the oil would not be recoverable by other means. Operators in both Egypt and Syria have been using thermal flooding since 2008. In Egypt’s Issaran oil field cyclic steam stimulation has increased production to 4,000 b/d from 50 b/d under primary and secondary recovery. In Syria, the Oudeh oil field went to an output of 850 b/d from 550 b/d and Tishrane oil field went to 2,500 b/d from 750 b/d. The potential for increasing this method of harvesting in Egypt is huge. As pointed out by Abu El-Ela, there are 3 billion barrels of this type of heavy oil that can be recovered throughout Egypt – 40% in the Eastern Desert, 39% in the Gulf of Suez, 18% in the Sinai, and 3% in the Western Desert.
Steam Flooding is a way of introducing heat to the reservoir by pumping steam into the well using a similar pattern to water injection. The steam eventually cools enough to form hot water. In the steam zone, the oil evaporates and in the hot water zone, it expands. When the oil expands, the viscosity drops and the permeability increases. The process must be cyclical to ensure success. This is the principal EOR program used today. Solar EOR is a form of steam flooding that uses the sun’s rays to generate heat water to make steam. Solar EOR is rapidly becoming an alternative to gas-fired steam production for the oil industry, as reported by the Clean Air Task Force.
Fire Flooding is a method that is employed when the oil saturation and porosity are high. Combustion generates the heat within the reservoir itself. Air or gas mixtures with high oxygen content are injected continuously to maintain the flame front. As the fire burns, it moves through the reservoir to the production wells. The heat reduces the oil’s viscosity and helps vaporize the water in the reservoir, turning it into steam. The steam, hot water, combustion gas, and dissolved solvent all act to drive the oil in front of the fire to the production wells.
There are three methods of combustion – dry forward, reverse, and wet combustion. Dry for uses an igniter to set fire to the oil. As the fire progresses the oil is pushed away from the fire toward the producing well. In reverse the air injection and the injection occur from opposite directions. In wet, water is injected just behind the front and turned into steam by the hot rock. This quenches the fire and spreads the heat more evenly.
The vast majority of EOR projects are being done in connection with onshore operations; however, technological improvements are coming to the forefront that will make these methods more accessible to offshore operations. The largest obstacle is that of the economics of development. There are weight, space, and power-limiting factors in retrofitting offshore facilities. Also, there are fewer wells that are spaced farther apart. This contributes to displacement, sweep, and lag time. With the coming of subsea processing and secondary recovery methods employed in offshore recovery projects, EOR underwater expansion is only a matter of time, as reported in Rig Zone.
The one thing that all of these Enhanced Oil Recovery methods have in common is that they add to the cost of the oil. In the case of carbon dioxide, the additional cost is between .5 and 8 USD per ton of CO2. It also leads to increased amounts of harvested oil, and the amount of the benefit depends upon the prevailing oil price at the time. Many of the procedures discussed have only come to the forefront recently, as the price of oil has climbed to over 100 USD per barrel and appears to be maintaining at that point for the immediate future, according to Reuters. Much of the technology existed, but was not used or advanced because it was not economically effective. Prevailing prices depend upon many factors, but can determine the economic suitability of any procedure, with more procedures and more expensive procedures being economically viable at higher prices.
Aside from the economic impact, the environmental impact needs to be considered as well. According to the United States Environmental Protection Agency, Enhanced Oil Recovery wells typically pump large amounts of brine to the surface. Not only is the water too salty to drink, it can have potentially toxic heavy metals, as well as radioactive particles. All of these have the potential to threaten the drinking water supply and the environment in general if not monitored properly.
There has been much screening for EOR in Egypt. The procedure of screening is based on field results and previous experience, and includes analysis of both surface and subsurface conditions. Results indicate that the most appropriate methods are CO2 and alkali-surfactant-polymer injection methods. The study shows that Egypt CO2 EOR by itself, could not only help Egypt reduce its CO2 emissions, but could increase the oil recovery factor by 5 to 15%, as researched by Schulmberger.
Egypt is at a crossroads. If it is to find a solution to its political and economic problems, the energy sector simply must play a leading role, a role not only in exports, but also in providing affordable energy to its population. Enhanced Oil Recovery is going to be a large part of this recovery. Lately, there has been much written about new discoveries of oil and gas in places not expected. Sudan, Israel, Argentina, the South China Sea, and eastern Brazil all come to mind. Egypt may very well have discovered more sites by now than it will in the future, but consider this – there may be as much as twice the amount of oil and gas under the ground as Egypt has brought up, used or sold since it began doing so over one hundred years ago, just waiting to be harvested. Where the wells are is known. No exploration has to be done to find them. All that has to be done is to find the proper EOR method and harvest the oil. These technologies will bring in profitable years of oil and gas for the future if the initiative is taken.
By Curt ChampeonDownload