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Fundamentals of Finding & Producing Oil & Gas in the Illinois Basin
Hydrocarbons - crude oil and natural gas - are found in certain layers of rock that are usually buried deep beneath the surface of the earth. In order for a rock layer to qualify as a good source of hydrocarbons, it must meet several criteria.
Characteristics of Reservoir Rock
For one thing, good reservoir rocks (a reservoir is a formation that contains hydrocarbons) have porosity. Porosity is a measure of the openings in a rock, openings in which petroleum can exist. Even though a reservoir rock looks solid to the naked eye, a microscopic examination reveals the existence of tiny openings in the rock. These openings are called pores. Thus a rock with pores is said to be porous and is said to have porosity (Figure 1).

Figure 1: Porosity

Another characteristic of reservoir rock is that it must be permeable. That is, the pores of the rock must be connected together so that hydrocarbons can move from one pore to another (Figure 2). Unless hydrocarbons can move and flow from pore to pore, the hydrocarbons remain locked in place and cannot flow into a well. In addition to porosity and permeability reservoir rocks must also exist in a very special way. To understand how, it is necessary to cross the time barrier and take an imaginary trip back into the very ancient past.

Figure 2: Permeability

Imagine standing on the shore of an ancient sea, millions of years ago. A small distance from the shore, perhaps a dinosaur crashes through a jungle of leafy tree ferns, while in the air, flying reptiles dive and soar after giant dragonflies. In contrast to the hustle and bustle on land and in the air, the surface of the sea appears very quiet. Yet, the quiet surface condition is deceptive. A look below the surface reveals that life and death occur constantly in the blue depths of the sea. Countless millions of tiny microscopic organisms eat, are eaten and die. As they die, their small remains fall as a constant rain of organic matter that accumulates in enormous quantities on the sea floor. There, the remains are mixed in with the ooze and sand that form the ocean bottom.

As the countless millennia march inexorably by, layer upon layer of sediments build up. Those buried the deepest undergo a transition; they are transformed into rock. Also, another transition occurs: changed by heat, by the tremendous weight and pressure of the overlying sediments, and by forces that even today are not fully understood, the organic material in the rock becomes petroleum. But the story is not over.

For, while petroleum was being formed, cataclysmic events were occurring elsewhere. Great earthquakes opened huge cracks, or faults, in the earth’s crust. Layers of rock were folded upward and downward. Molten rock thrust its way upward, displacing surrounding solid beds into a variety of shapes. Vast blocks of earth were shoved upward, dropped downward or moved laterally. Some formations were exposed to wind and water erosion and then once again buried. Gulfs and inlets were surrounded by land, and the resulting inland seas were left to evaporate in the relentless sun. Earth’s very shape had been changed.

Meanwhile, the newly born hydrocarbons lay cradled in their source rocks. But as the great weight of the overlying rocks and sediments pushed downward, the petroleum was forced out of its birthplace. It began to migrate. Seeping through cracks and fissures, oozing through minute connections between the rock grains, petroleum began a journey upward. Indeed, some of it eventually reached the surface where it collected in large pools of tar, there to lie in wait for unsuspecting beasts to stumble into its sticky trap. However, some petroleum did not reach the surface. Instead, its upward migration was stopped by an impervious or impermeable layer of rock. It lay trapped far beneath the surface. It is this petroleum that today’s oilmen seek.

Types of Petroleum Traps

Geologists have classified petroleum traps into two basic types: structural traps and stratigraphic traps. Structural traps are traps that are formed because of a deformation in the rock layer that contains the hydrocarbons. Two common examples of structural traps are fault traps and anticlines.

An anticline is an upward fold in the layers of rock, much like an arch in a building. Petroleum migrates into the highest part of the fold, and its escape is prevented by an overlying bed of impermeable rock (A).
A fault trap occurs when the formations on either side of the fault have been moved into a position that prevents further migration of petroleum. For example, an impermeable formation on one side of the fault may have moved opposite the petroleum-bearing formation on the other side of the fault. Further migration of petroleum is prevented by the impermeable layer (B).
Stratigraphic traps are traps that result when the reservoir bed is sealed by other beds or by a change in porosity or permeability within the reservoir bed itself. There are many different kinds of stratigraphic traps. In one type, a tilted or inclined layer of petroleum-bearing rock is cutoff or truncated by an essentially horizontal, impermeable rock layer (C).

Or sometimes a petroleum-bearing formation pinches out; that is, the formation is gradually cut off by an overlying layer. Another stratigraphic trap occurs when a porous and permeable reservoir bed is surrounded by impermeable rock. Still another type occurs when there is a change in porosity and permeability in the reservoir itself. The upper reaches of the reservoir may be impermeable and nonporous, while the lower part is permeable and porous and contains hydrocarbons.


Once a likely area has been selected, the right to drill must be secured before drilling can begin. Securing the right to drill usually involves leasing the mineral rights of the desired property from the owner. The owner may be the owner of all interest in the land, or just the mineral rights. As payment for the right to drill for and extract the oil and gas, the owner will usually be paid a sum call a "lease bonus" or a "hole bonus" for every well drilled on the leased land. He will also retain a royalty on the production, if any, of the leased property. The royalty is the right to receive a certain portion of the production of property, without sharing in the costs incurred in producing the oil, such as drilling, completion, equipping and operating or production costs. The costs are borne by the holder of the right to drill and extract the mineral, which right is usually referred to as the working interest.In many cases the procurement of the lease from the land owner is accomplished by a lease broker who will, in turn, offer and then assign the lease to an operator such as MMD Energy, Inc. MDM Energy is very selective in choosing leases for drilling. The lease broker may retain an overriding royalty on the working interest as compensation for his services. .

Once an area has been selected and the right to drill thereon has been obtained, actual drilling may begin. The most common method of drilling in use today is rotary drilling. Rotary drilling operates on the principle of boring a hole by continuous turning of a bit. The bit is the most important tool. The rest of the rig ( a derrick and attendant machinery) is designed to make it effective. While bits vary in design and purpose, one common type consists of a housing and three interlocking movable wheels with sharp teeth, looking something like a cluster of gears. The bit, which is hollow and very heavy, is attached to the drill stem, composed of hollow lengths of pipe leading to the surface. As the hole gets deeper, more lengths of pipe can be added at the top. Almost as important as the bit is the drilling fluid. Although known in the industry as mud, it is actually a prepared chemical compound. The drilling mud is circulated continuously down the drill pipe, through the bit, into the hole and upwards between the hole and the pipe to a surface pit, where it is purified and recycled. The flow of mud removes the cuttings from the hole without removal of the bit, lubricates and cools the bit in the hole, and prevents a blow out which could result if the bit punctured a high pressure formation. (See the drilling rig to the right.)

The cuttings, which are carried up by the drilling mud, are usually continuously tested by the petroleum geologist in order to determine the presence of oil.

The final part of the hole is what the operating company hopes will be the production hole. But before long, the formation of interest (the pay zone, the oil sand, or the formation that is supposed to contain hydrocarbons) is penetrated by the hole. It is now time for a big decision. The question is, "Does this well contain enough oil or gas to make it worthwhile to run the final production string of casing and complete the well?"


Examining Cuttings
To help the operator make his decision, several techniques have been developed. One thing that helps indicate whether hydrocarbons have been trapped is a thorough examination of the cuttings brought up by the bit. The mud logger or geologist (Remember him? He’s been there all along, monitoring downhole conditions at the location.) catches cuttings at the flow ditch and by using a microscope or ultraviolet light can see whether oil is in the cuttings. Or he may use a gas-detection instrument.

Well Logging

Another valuable technique is well logging. A logging company is called to the well while the crew trips out all the drill string. Using a portable laboratory, truck-mounted for land rigs, the well loggers lower devices called logging tools into the well on wireline. The tools are lowered all the way to bottom and then reeled slowly back up. As the tools come back up the hole, they are able to measure the properties of the formations they pass.Electric logs measure and record natural and induced electricity in formations. Some logs ping formations with sound and measure and record sound reactions. Radioactivity logs measure and record the effects of natural and induced radiation in the formations. These are only a few of many types of logs available. Since all the logging tools make a record, which resembles a graph or an electrocardiogram (EKG), the records, or logs can be studied and interpreted by an experienced geologist or engineer to indicate not only the existence of oil or gas, but also how much may be there. Computers have made the interpretation of logs much easier.


In addition to these tests, formation core samples are sometimes taken. Two methods of obtaining cores are frequently used. In one, an assembly called a "core barrel" is made up on the drill string and run to the bottom of the hole. As the core barrel is rotated, it cuts a cylindrical core a few inches in diameter that is received in a tube above the core-cutting bit. A complete round trip is required for each core taken. The second is a sidewall sampler in which a small explosive charge is fired to ram a small cylinder into the wall of the hole. When the tool is pulled out of the hole, the small core samples come out with the tool. Up to thirty of the small samples can be taken at any desired depth. Either type of core can be examined in a laboratory and may reveal much about the nature of the reservoir.


After the operating company carefully considers all the data obtained from the various tests it has ordered to be run on the formation or formations of interest, a decision is made on whether to set production casing and complete the well or plug and abandon it. If the decision is to abandon it, the hole is considered to be dry, that is, not capable of producing oil or gas in commercial quantities. In other words, some oil or gas may be present but not in amounts great enough to justify the expense of completing the well. Therefore, several cement plugs will be set in the well to seal it off more or less permanently. However, sometimes wells that were plugged and abandoned as dry at one time in the past may be reopened and produced if the price of oil or gas has become more favorable. The cost of plugging and abandoning a well may only be a few thousand dollars. Contrast that cost with the price of setting a production string of casing - $50,000 or more. Therefore, the operator’s decision is not always easy.

Setting Production Casing

If the operating company decides to set casing, casing will be brought to the well and for one final time, the casing and cementing crew run and cement a string of casing. Usually, the production casing is set and cemented through the pay zone; that is, the hole is drilled to a depth beyond the producing formation, and the casing is set to a point near the bottom of the hole. As a result, the casing and cement actually seal off the producing zone-but only temporarily. After the production string is cemented, the drilling contractor has almost finished his job except for a few final touches.


After the casing string is run, the next task is cementing the casing in place. An oil-well cementing service company is usually called in for this job although, as when casing is run, the rig crew is available to lend assistance. Cementing service companies stock various types of cement and have special transport equipment to handle this material in bulk. Bulk-cement storage and handling equipment is moved out to the rig, making it possible to mix large quantities of cement at the site. The cementing crew mixes the dry cement with water, using a device called a jet-mixing hopper. The dry cement is gradually added to the hopper, and a jet of water thoroughly mixes with the cement to make a slurry (very thin water cement).

Special pumps pick up the cement slurry and send it up to a valve called a cementing head (also called a plug container) mounted on the topmost joint of casing that is hanging in the mast or derrick a little above the rig floor. Just before the cement slurry arrives, a rubber plug (called the bottom plug) is released from the cementing head and precedes the slurry down the inside of the casing. The bottom plug stops or "seats" in the float collar, but continued pressure from the cement pumps open a passageway through the bottom plug. Thus, the cement slurry passes through the bottom plug and continues on down the casing. The slurry then flows out through the opening in the guide shoe and starts up the annular space between the outside of the casing and wall of the hole. Pumping continues and the cement slurry fills the annular space.

A top plug, which is similar to the bottom plug except that it is solid, is released as the last of the cement slurry enters the casing. The top plug follows the remaining slurry down the casing as a displacement fluid (usually salt water or drilling mud) is pumped in behind the top plug. Meanwhile, most of the cement slurry flows out of the casing and into the annular space. By the time the top plug seats on or "bumps" the bottom plug in the float collar, which signals the cementing pump operator to shut down the pumps, the cement is only in the casing below the float collar and in the annular space. Most of the casing is full of displacement fluid.

After the cement is run, a waiting time is allotted to allow the slurry to harden. This period of time is referred to as waiting on cement or simply WOC.

After the cement hardens, tests may be run to ensure a good cement job, for cement is very important. Cement supports the casing, so the cement should completely surround the casing; this is where centralizers on the casing help. If the casing is centered in the hole, a cement sheath should completely envelop the casing. Also, cement seals off formations to prevent fluids from one formation migrating up or down the hole and polluting the fluids in another formation. For example, cement can protect a freshwater formation (that perhaps a nearby town is using as its drinking water supply) from saltwater contamination. Further, cement protects the casing from the corrosive effects that formation fluids (as salt water) may have on it.


Since the pay zone is sealed off by the production string and cement, perforations must be made in order for the oil or gas to flow into the wellbore. Perforations are simply holes that are made through the casing and cement and extend some distance into the formation. The most common method of perforating incorporates shaped-charge explosives (similar to those used in armor-piercing shells).
Shaped charges accomplish penetration by creating a jet of high-pressure, high-velocity gas. The charges are arranged in a tool called a gun that is lowered into the well opposite the producing zone. Usually the gun is lowered in on wirelin (1). When the gun is in position, the charges are fired by electronic means from the surface (2). After the perforations are made, the tool is retrieved (3). Perforating is usually performed by a service company that specializes in this technique.


Sometimes, however, petroleum exists in a formation but is unable to flow readily into the well because the formation has very low permeability. If the formation is composed of rocks that dissolve upon being contacted by acid, such as limestone or dolomite, then a technique known as acidizing may be required. Acidizing is usually performed by an acidizing service company and may be done before the rig is moved off the well; or it can also be done after the rig is moved away. In any case, the acidizing operation basically consists of pumping anywhere from fifty to thousands of gallons of acid down the well. The acid travels down the tubing, enters the perforations, and contacts the formation. Continued pumping forces the acid into the formation where it etches channels - channels that provide a way for the formation’s oil or gas to enter the well through the perforations.

When sandstone rocks contain oil or gas in commercial quantities but the permeability is too low to permit good recovery, a process called fracturing may be used to increase permeability to a practical level. Basically, to fracture a formation, a fracturing service company pumps a specially blended fluid down the well and into the formation under great pressure. Pumping continues until the formation literally cracks open.Meanwhile, sand, walnut hulls, or aluminum pellets are mixed into the fracturing fluid. These materials are called proppants. The proppant enters the fractures in the formation, and, when pumping is stopped and the pressure allowed to dissipate, the proppant remains in the fractures. Since the fractures try to close back together after the pressure on the well is released, the proppant is needed to hold or prop the fractures open. These propped-open fractures provide passages for oil or gas to flow into the well. See figure to the right.

After the well has been perforated, acidized or fractured, the well may not produce by natural flow. In such cases, artificial-lift equipment is usually installed to supplement the formation pressure.

Sucker-Rod Pumps

The artificial-lift method that involves surface pumps is known as rod pumping or beam pumping. Surface equipment used in this method imparts an up-and-down motion to a sucker-rod string that is attached to a piston or plunger pump submerged in the fluid of a well. Most rod-pumping units have the same general operating principles.


In the ordinary producing operation only a portion of the oil in place is recoverable by primary production methods. Such methods include free-flowing wells and production maintained by pumps. As oil is extracted from a reservoir or sands the pressure which brings the oil to the well is reduced. Secondary recovery methods are intended to increase the recoverable percentage of the oil in place by injecting a substance such as gas or water into the producing formation. The injected substance is intended to increase the pressure on the oil in the formation and drive it toward the well-bore. A well, called an injection well or water injection well, is usually drilled in order to inject the substance. Sometimes a previously drilled, abandoned well can be reworked as an injection well. When water is used as the injectant it is often produced on the property itself. Excess water produced by operating wells may be diverted to the injection well and used as the injectant. This method of water disposal usually alleviates the need for a separate water disposal well. If the water from the producing wells does not provide enough injectant to provide proper pressure for secondary recovery, a water supply well may be required to provide an adequate supply of water.

Once an accumulation of oil has been found in a porous and permeable reservoir, a series of wells are drilled in a predetermined pattern to effectively drain this "oil pool". Wells may be drilled as close as one to each 10 aces (660 ft. between wells) or as far apart as one to each 640 acres (1 mile between wells) depending on the type of reservoir and the depth to the "pay" horizon. For economic reasons, spacing is usually determined by the distance the reservoir energy will move commercial quantities of oil to individual wells.The rate of production is highest at the start when all of the energy from the dissolved gas or water drive is still available. As this energy is used up, production rates drop until it becomes uneconomical to operate although significant amounts of oil still remain in the reservoir. Experience has shown that only about 12 to 15 percent of the oil in a reservoir can be produced by the expansion of the dissolved gas or existing water.


Waterflooding is one of the most common and efficient secondary recovery processes. Water is injected into the oil reservoir in certain wells in order to renew a part of the original reservoir energy. As this water is forced into the oil reservoir, it spreads out from the injection wells and pushes some of the remaining oil toward the producing wells. Eventually the water front will reach these producers and increasingly larger quantities of water will be produced with a corresponding decrease in the amount of oil. When it is no longer economical to produce these high water-ratio wells, the flood may be discontinued.As mentioned previously, average primary recoveries may be only 15% of the oil in the reservoir. Properly operated waterfloods should recover an additional 15% to 20% of the original oil in place. This leaves a substantial amount of oil in the reservoir, but there are no other engineering techniques in use now that can recover it economically.In most cases, oil reservoirs suitable for secondary recovery projects have been produced for several years. It takes time to inject sufficient water to fill enough of the void spaces to begin to move very much oil. It takes several months from the start of a waterflood before significant production increases take place and the flood will probably have maximum recoveries during the second, third, fourth, and fifth years after injection of water has commenced. The average flood usually lasts 6 to 10 years.


Waterfloods have been highly successful in the Illinois Basin and probably account for 75% of the total production from the area. Flood recoveries will generally be an additional 80% to 100% of the primary production.There are no special problems with floods in the Illinois Basin. Ample supplies of salt water are generally available and injection pressures are not too high - 1500 PSI or less. Corrosion is minimal and no expensive, high-pressure equipment is involved. Sufficient potential flood properties are available on reasonable terms - especially smaller areas owned by independent operators who do not have the finances to support the installation of properly engineered secondary recovery operations.Waterfloods in the Illinois Basin should return 4 to 6 times their cost and are considered to be low-risk prospects.


When all equipment is in place, the oil may begin to flow into the holding tanks to await pick up. It can be expected that a well will not be in production for certain times due to adverse weather conditions, mechanical malfunctions and other unforeseen circumstances. After the production period commences, it is necessary to incur certain costs in order to bring the oil to the surface. These costs include normal maintenance on the pump and other equipment, replacement of any pipe or tanks as needed, compensation to the operator of the pump, and payment of any incidental damages to the owner of the surface rights of the leased property. In some cases, the oil in a pay zone will be mixed with salt water. In such cases, the oil must be separated from the salt water and the salt water disposed of in a manner which is not harmful to the environment. The water may be hauled away by tank truck but often this phenomenon requires the drilling, nearby the oil producing well, of another well into which the salt water will be pumped. The cost of this water disposal well is normally considered to be a cost of operation. Finally, there may be additional costs incurred in opening up a new pay zone when any presently producing pay zone becomes economically unfeasible. Because opening a new pay zone involves the installation of very little, if any, new equipment, the costs involved therein usually are not very substantial.


Once the oil is out of the ground and into the holding tanks, it must be sold. In most cases each holder of a working interest has the right to take his portion of production in kind, therefore, make his own arrangements for its sale. It is not uncommon, however, for all the holders of a working interest of a well to enter into the same arrangement with the same buyer of the oil production. These sale contracts are normally entered into for periods of not longer than a few months but in no case longer than one year. The buyer of the oil will generally be advised by the operator of the working interest as to the identity and extent of ownership of each of the holders of the working interest, as well as the identity of the royalty holders and the amount of their interests. The information will be compiled on division orders which are the basis upon which the buyer of the oil can divide the proceeds of sale among the various holders. The buyer of the oil will pick up the oil from the holding tanks at periodic intervals, gauge it and remit the remaining proceeds in the proper amounts to the holders of the working interest and the royalties.