This section contains information about:
|Casing||Developing a field||Drill Stem Test|
|Horizontal Wells||Reservoir Pressure||Reservoir Temperature|
|Stimulating a Well||Surface Completion Testing||Tubing|
|Enhanced Oil Recovery||SAGD (past)||SAGD (present)|
Once oil is reached, there is the problem of recovering it, that is moving it to the surface and off to the battery and eventually to the refinery. That’s where my heaviness causes problems. Conventional crude oil often moves to the surface on its own, sometimes with great force. This is called "kicking in" and it happened sometimes in the early days right here in the Lloydminster field. The pressure of gas or water drove the oil to the surface in the classic gusher unless it was controlled.
Heavy oil, like me, doesn’t rush to the surface. In fact, it’s a problem for which new solutions are still being developed, just to lift me out of the ground. That’s why there was such disappointment in the early days when I was discovered. Sometimes a well was even shut in because while the baling showed oil, it was just too difficult or too slow to pump out.
Before I get into those problems, let me finish with the completion of a well that can be pumped using conventional technology.
When a well comes in with a bang!
Not common in the Heavy Oil patch
Completing a well can be very expensive. After drilling a well, someone must decide if the well is worth the expenses of completion. This is known to the investor as the casing point. Did the well encounter petroleum bearing reservoirs? If so, at what depth and how thick were the reservoirs? What is the oil saturation? Is there enough petroleum to make the well commercial?
Some of these answers could come from a sample log. The well-sitting geologist could have identified reservoir zones in the well. Perhaps there was oil staining on some samples or a show of gas or oil in the drilling mud. If a mud logger was employed at the well site, petroleum-bearing reservoirs would have been delineated in the mud log. The reservoirs could even have been sampled by coring. Most often, however, openhole, wire-line well logs are used to evaluate the well. Reservoirs can be delineated by SP and gamma ray logs. Porosity is determined by neutron porosity, formation density, and sonic logs. The presence of hydrocarbons is detected by a resistivity log (electrical or induction) from which oil saturation can be computed. Gas can be detected by the gas effect of neutron porosity and formation density logs. Permeability is the only important reservoir characteristic that cannot be quantitatively determined from wire-line well logs. Permeable zones, however, can be delineated by the thickness of the filter cake. Thicker filter cake builds up in the well bore adjacent to permeable zones. This shows that considerable drilling mud has infiltrated into the rock. Thick filter cake can be located by a caliper log that measures the diameter of the well bore or a microlog. A microlog is an electrical resistivity log with closely spaced electrodes. It can be used to sense the thickness of the filter cake.
The drill stem test is used primarily to determine the fluids present in a particular formation and the rate at which they can be produced. The test is run in a bare hole filled with drilling mud. Pressure exerted by the drilling mud in the well prevents fluids from flowing out of the reservoir rocks into the well. A hollow pipe called a drill stem is lowered down the well. The drill stem has two expendable, devices, called packers, around it. The drill stem is lowered into the well until one packer is just above the formation to be tested and the other below. The packers are then expanded to close the well above and below the formation. Sealing the well around the formation eliminates the pressure exerted by drilling mud on the formation. Water, gas, or oil can flow out of the formation and into the well. A trap door is opened on the drill stem and the formation fluids flow into and up the drill stem. If gas is present, it will flow up the drill stem and onto the surface where it is measured and flared (burned). Sometimes oil has enough pressure to flow to the surface during a drill stem test. Usually, however, the oil fills the drill stem to a certain level. This is measured and recorded. During the drill stem test, pressure of the fluid flowing into the drill stem is continuously being measured by an instrument in the drill stem. The trap door on the drill stem is opened and closed several times and fluid pressure build up and drop are recorded. These records are used by engineers to calculate formation permeability, reservoir fluid pressure, and extent of formation damage.
The first step in completing the hole is casing. Casing is steel pipe that is run down the hole. Cement (slurry) is then pumped between the casing and sides of the well. Casing has three purposes. It stabilizes the well and prevents the sides from caving into the well. Casing protects fresh water aquifers that are often located near the surface. The protection of fresh water resources from possible contamination is a major concern of the petroleum industry. Casing seals off these reservoirs from pollution by drilling mud during drilling and petroleum during production. The casing also prevents the petroleum from being diluted by waters from other formations during production.
Many wells have a casing program. Surface casing extends from the surface to approximately 150 meters. It protects freshwater aquifers and prevents loose surface rock from caving into the well. Surface casing has a large diameter, for example, 244.5 mm outside diameter (OD). Production casing is run down past the producing horizons. It has the smallest diameter, typically 178 mm or 139.7 mm in the heavy oil area. The total length of a particular type of casing is called a string. A large-diameter bit is used to drill the near surface portion of the well. After the surface casing string is run into the well, a smaller diameter bit is used to drill the next portion of the well.
If the well bottoms out in the producing formation, an open hole completion can be used. The well is cased down to the top of the producing formation and left open below that. If the reservoir is loose sand, a screen, gravel pack, or slotted liner can be put on the bottom of the well to prevent the well from becoming clogged. These types of completions are usually done in horizontal wells. A vertically cased well is usually completed with perforations. The casing is run down the length of the well and a casing shoe closes off the bottom. A perforating gun is lowered into the well until adjacent to the reservoir zone. The gun uses shaped explosive charges that are detonated to blow holes (perforations) in the casing, cement, and reservoir rock. This makes a very clean system; only fluids from the reservoir rock can flow into the well. Multiple completions on several reservoir zones in the same well are done by perforations.
Small-diameter pipe called tubing is run into the well to conduct the petroleum to the surface. Tubing ranges from 30 mm to over 110 mm in diameter. It is suspended in the well from the surface down to near the producing zone. The pressure on oil in most heavy oil zones is enough to force the oil into the well but not to the surface. A pump is run on the bottom of the tubing to pump oil to the surface.
One well known completions and service expert was Jack Roberts. He told the following story:
"In the late 1960’s I worked for PGAC (Pan-Geo Atlas Corporation), a well perforating company. I remember perforating a well for Fargo east of Lloydminster near Aberfeldy where the new Saskatchewan weigh scales are. We didn’t use a lubricator, only a packoff, because the wells NEVER blow in here. There was no valve or Blowout Preventer on the well either. This well was not normal because as soon as we shot it there was pressure at surface. With no lubricator we had to wait for a pressure truck to kill the well. The company man was upset, not because the well came in, but because he would have to bale the well down again after he killed it. Rigtime was a big concern even in the sixties."
In most oil wells, the oil has to be pumped to the surface through the tubing. The pumping unit is powered by an engine or prime mover that is usually electrical, natural gas or propane powered. The engine causes the walking beam to pivot up and down. As the end of the walking beam is raised and lowered, sucker rods are raised and lowered in the well. The sucker rods operate the pump at the bottom of the well. Increasingly, rotary action wells are being used in our local heavy oil fields. For example, a progressive cavity pump uses a rotating sucker rod to lift the oil to the surface.
Baling is a technique that is used to start the well flowing. A baling tool, commonly called a baler, is lowered down the well. As the baler is brought back up the well, the fluid in the well is carried up the well and removed. This lowers the level of fluid in the well, decreasing the pressure on the reservoir fluids. The reservoir fluids can then flow into the well.
Some oil wells produce considerable salt water along with the oil. Gas also bubbles out of the oil. In order to separate the oil, water, and gas, the fluids can be put into a separator. The separator is a tank that is either vertical or horizontal and uses gravity to separate the fluids. Gas goes to the top, and the heavier salt water goes to the bottom. In the past, where there was no market for the gas, it was often flared (i.e. burned at the well site). Today, casing gas is used to power pump engines or heat storage tanks. Most gas never gets to a battery and therefore does not need to be separated out. The oil field brine is usually pumped down an injection well. Oil is piped to stock tanks where it is stored. If the water and oil are mixed in an emulsion, the separator must be heated to separate the fluids. Today, chemicals are most often used to separate the emulsion components and this usually happens in the wellsite tank.
Some oil wells produce considerable sand along with the oil, as much as 60%. This sand separates out in the wellsite tank and has to be cleaned out occasionally. Sand disposal has become the most difficult environmental challenge yet. It has been layered on roads, stored in huge underground caverns, pumped back into formations, and washed clean and used for industrial purposes.
After the well has been completed, a "potential test" can be run. This test will show the maximum amount of oil that the well can produce in a 24 hour period.
An exploratory well in a new area is called a wildcat well. If the well is the first in a field, it is called the discovery well. Wells drilled to the side of the discovery well to determine the extent of the field are called stepouts. Once stepping out has defined the field, wells drilled in the known extent of the field are called development wells. Drilling wells more closely together in an old field to produce more petroleum is known as in-fill drilling. The risk of a dry hole greatly decreases from wildcat to step-out to developmental to in-fill wells.
In the early days, there were no rules on the spacing of wells or the rate of production. Oil fields were often developed with wells spaced as closely as possible, producing as fast as possible. If your well pumped oil out from under your neighbor's lease, it was legally yours. A lot of oil was wasted by this policy. Regulatory agencies today control the spacing and production of petroleum.
As I mentioned earlier, my extra weight means that often other ways must be found to recover me from the reservoir. Generally, we can refer to these ways as enhanced recovery techniques.
There are several methods to stimulate a reservoir that is not producing at a fast enough rate.
Up to the 1940s, wells were sometimes given a shot of explosives to increase the permeability of the reservoir zone. Well shooting (explosive fracturing) was usually done with nitroglycerin, which was dangerous and sometimes exploded prematurely. The technique, however, was very effective.
The temperature of the rocks and the fluids in the rocks increases with depth. The rate of temperature increase with depth is the geothermal gradient. It is expressed in degrees Celsius per 100 meters of depth. The geothermal gradient is known in many areas and has been published. In an individual well, temperature is measured with a temperature bomb that is lowered into the well. This is done after the well has been left for several days to come to thermal equilibrium. By subtracting the mean annual surface temperature from the formation temperature and dividing by the depth of the formation from the surface, the geothermal gradient of that well can be calculated.
Geothermal gradients vary considerably. In some deep wells, the temperature of the produced oil can be as high as 150 degrees Celsius. In the Lloydminster area, however, the temperature of produced oil ranges from 15 to 25 degrees Celsius. This relatively cool temperature is just one more of the many problems which makes it difficult to pump heavy oil.
In a typical subsurface reservoir, there is one pressure on the fluid in the sand and another pressure on the sand itself. The pressure on the sand is generated by the weight of overlying burden. The deeper the reservoir, the greater the pressure. The fluid pressure increase with depth is the hydrostatic pressure gradient and is expressed in kpa [kilopascals]. It is also influenced by the density of the overlying fluid, usually water. Water density is controlled primarily by its salinity. Hydrostatic gradients range from a low of [we need metric equivalents for the following] 43.3 psi per 100 feet for fresh water to values as high as 52 psi per 100 feet for saline brines. The average is 45 psi per 100 feet (55 ppt salinity). Hydrostatic pressure on a fluid in the pores of a subsurface reservoir can be calculated by multiplying the depth of the reservoir from the surface times the hydrostatic gradient. This assumes that the water table is approximately at the surface. The depth of heavy oil wells in the Lloydminster area ranges from 350 to 800 meters.
Reservoir, fluid, and formation pressures are the pressures on the fluid in the pore spaces of the reservoir. Under normal conditions, it is hydrostatic pressure. Bottom hole pressure is the pressure on the fluids at the bottom of the well after the well has been left to come into hydrostatic equilibrium with fluids in the surrounding reservoir. Bottom hole and formation pressures are usually the same. Reservoir pressure before any production is original or virgin pressure. As fluids are produced, reservoir pressure decreases. Flowing or bottom hole flowing pressure is the pressure on the bottom of the well measured as the well is producing. When the well is shut in, the pressure will build back up to a maximum called the static bottom hole, shut in, or static formation pressure. This pressure will never be as high as the original pressure because fluids have been removed from the reservoir. Differential pressure is the difference between flowing and static pressure in a well. Casing or surface pressure is the pressure on the casing at the top of the well after the well has been shut in and the pressure allowed to build up. Tubing pressure is the pressure on the tubing at the top of the well.
Pressure in a well can be determined by a self-recording instrument, called a pressure bomb, that is lowered down the well. In a producing well, the pressure bomb can be lowered into the tubing adjacent to the reservoir. Shut in pressures can be calculated by measuring casing pressures. If the well is filled with water, the height to which the water rises (static water level) can be used to calculate reservoir pressure.
Pressure on the rock is generated by the weight of the overlying sediments. The deeper the reservoir, the more pressure (overburden pressure) on the rocks. The increase in rock pressure with depth is called the lithostatic, geostatic, or overburden pressure gradient. It is expressed in psi per 100 feet of depth. An average lithostatic pressure gradient for a sedimentary rock basin is 100 psi per 100 feet. The pressure on a subsurface rock is calculated by multiplying the depth from the surface to the rock times 100 psi per 100 feet.
The higher the pressures on oil, the more gas can be dissolved in the oil. Viscosity of the oil is reduced with higher concentrations of dissolved gas. The deeper the oil reservoir, the hotter the oil, and the more gas it can have dissolved. Both these factors reduce the viscosity of the oil and allow it to flow through the reservoir rocks more readily. As we have seen, Lloydminster area heavy oil is relatively shallow, cool, and has little dissolved gas. All of this means increased viscosity and thus the slow moving, difficult to produce heavy oil such as Crudey.
Enhanced Oil Recovery
Primary recovery is oil production using the original reservoir drive energy. It produces an average of 30% of the oil in place. This leaves a considerable amount of oil in the reservoir after the reservoir pressures have been depleted. Because of this, procedures called enhanced oil recovery are used to produce more oil. Secondary recovery is the technique used after primary recovery. Tertiary recovery follows secondary recovery.
A water flood involves injecting water into the depleted oil reservoir rock. It sweeps the remaining oil through the reservoir to producing wells. One water-flood injection method is the five-spot pattern. Four water-injecting wells are located at the corners of a square with a producing well at the centre. If there is an oil-water contact in the reservoir, the water is injected into the water portion of the reservoir to maintain a water drive.
Water floods work well in certain shoestring sandstones which are relatively uniform and encased in shale. In many reservoirs, however, the rock is not as uniform and water flood is not as efficient. Any water, gas, or oil will always flow along the route of least resistance. A reservoir might have a zone of high permeability, such as a well-sorted bed of sandstone or a porous or fractured zone in limestone. As the water flood sweeps through the reservoir, the injected water flows fastest through the permeable zone and reaches the producing well first. This is called breakthrough. Once the water has broken through, the rest of the water will tend to flow through that permeable zone bypassing oil in the less permeable portions of the reservoir. The sooner the water breaks through, the less efficient the water flood.
Heavy oils (API gravities from 10 to 20 degrees) have high viscosity and do not flow readily in conventional wells. Steam injection and steam flood are often used to produce heavy oil. Steam injection uses a well to inject steam into the heavy oil reservoir for a period of time such as two weeks. The steam heats up the heavy oil and makes it fluid. The same well is then used to pump the heated heavy oil for a similar period of time. Steam injection and pumping are alternated in this technique, called the huff and puff method. A steam flood involves injection wells that pump steam into the heavy oil reservoir. The pressure of the steam forces the heated heavy oil to a producing well between the injection wells.
A variation on this is one of many technological improvements developed in the Lloydminster area. Companies targeting heavy oil are not geological risk-takers; they are technology risk-takers. Retrieving heavy oil efficiently and economically takes heavy thinking. Several companies are leading the way with innovative technologies.
Heavy oil is similar to the oil locked in the oil sands - although not as thick, it is still difficult to produce by conventional means. Usually found several hundred meters below the surface, it can't be removed by open pit methods used for the oilsands. Western Canadians are at the leading edge of the new methods being developed to produce this oil. Heavy oil reservoirs are easier to find than conventional reservoirs, but they are not easy to produce economically, and depend heavily on new technologies.
Leaders among the companies focusing on heavy oil are CS Resources Limited and Elan Energy Inc. New regulatory and investment climates are helping foster development. Central to their efforts are horizontal wells and Steam Assisted Gravity Drainage (SAGD).
CS is a pioneer of horizontal drilling, which is becoming central to heavy oil production. In 1988, it drilled 10 horizontals, second to only one other company in the world.
At Pelican Lake, a lease acquired in 1989, CS realized the longer the horizontal part of the well, the more oil is reached per drilling dollar. The horizontal length of well is limited by the mechanics of drilling. With Sperry-Sun, CS developed a method of drilling laterals or branches from the main well. An average well with the main trunk and two branches costs roughly twice as much to drill, yet gives three tunes the reserves of a single horizontal. The latest well has five kilometers exposure to the reservoir, and produces 500 b/d. This technology benefits the environment as well, using fewer drilling pads to tap the reservoir.
SAGD, developed in 1977-78 by Dr. Roger Butler, involves the drilling of a pair of horizontal wells, one about four meters above the other. Steam injected into the reservoir through the upper well heats and mixes with the oil, reducing its viscosity to the point where it runs down through the reservoir to be removed by the lower well.
In 1995, CS Resources developed the first commercial scale dual well SAGD project, at Senlac, Saskatchewan. The development costs were $30 million for this 5,000 b/d facility, which helps to explain why others we not so quick to adopt this technology. The first of three initial well pairs had promising production at the 1,200-1,500 b/d level.
CS overcame many hurdles to get to the commercial stage. The producing well's horizontal section is drilled near the bottom of the reservoir, and undulates up and down as it follows the bottom contours. The challenge when drilling the injection well is to have consistent spacing above the producer. This is accomplished with an electromagnetic tool based on one used in drilling relief wells. A much clearer picture of the reservoir was needed in order to accurately place the wells. To achieve this, CS allied itself with Institut Francais de Petrole (IFP) to gain access to its worldwide technology. Extensive modeling of the reservoir was accomplished with computer power that wasn't available until recently.
CS also has plans to take SAGD technology outside Canada. The IFP affiliation is helping in this regard, bringing knowledge of suitable heavy oil reservoirs. A decision is expected within the next year.
Although industry was quick to embrace horizontal well technology, it probably will be slower to take up SAGD, due to the high cost of a single project, the lack of consulting knowledge available at this time plus many companies lack the necessary corporate culture to be involved in this sort of initiative - the driving force has to come from the executive suite and the board room.
Elan Energy is also tackling the challenge of heavy oil in a big way. They find that with heavy oil as compared to conventional reservoirs, you don't need big land spreads. This helps to offset the costs involved.
Elan is heading in a very different direction than CS with their technology, pioneering Single Well SAGD. With this method, the steam is injected and the oil produced at the same time through a single horizontal well. This is made possible with an innovation, Insulated Concentric Coiled Tubing, developed with NOWSCO Well Service Ltd. Steam is delivered to the very end of the horizontal well, called the "toe", through an insulated tube within the production tubing. The steam creates a zone around the well called a steam chamber. As it expands towards the vertical section of the well, it heats the oil and drives it to the production tubing.
Their first SW SAGD well has been producing since it was drilled at Cactus Lake, Saskatchewan in February 1995. Elan now has 12 in operation, and planned to drill another 68 in 1996. The benefits Elan has gained from SW SAGD include: early production results of 500-1000 b/d; recovery rates of about 50-70% of the oil in place; lower capital costs, since only one wellbore is required, and lower operating costs, with average to low steam requirements. Plus, more information is now being obtained through the use of fiber optic observation wells at the tenth installation.
Elan has also worked on improving pumping methods in heavy oil reservoirs. Total production can be up to 40% sand. With horizontal wells, screens are used at the well face to remove the sand. This is not possible with vertical wells - the sand chokes off production. Large quantities of sand quickly wear out or seize up the moving parts on conventional sucker rod pumps, so screw pumps are used in heavy oil wells. The pumps' static parts we made of rubber, with better wear resistance to the sand. They are usually driven by hydraulic motors at the surface and can employ conventional or continuous sucker rods.
Imperial Oil's Cold Lake project uses cyclic steam-stimulation, or "huff and puff'. Steam is injected through wells to heat and dilute the oil, which is later produced through the same well. Imperial plans to expand the Cold Lake operation from 96,000 to 150,000 b/d by 2000. Improvements include water conservation. "Huff and puff" depends on large quantities of water, and in the early days used mostly fresh water. Imperial now foresees the day when 90% of the water will be recycled.
With such developments in heavy oil, it is quickly taking a place alongside the oilsands in supplying a major part of Canada's energy needs.
So you see, people go to great efforts to recover me and
this makes me, Crudey, the Heavy Oil drop, feel very, very special.