Dee Three news posted by Poise The news shown by Dee Three as posted by Poise is fairly informative in comparison to other news released from the area and a lot can be logically deduced from it. Below is my interpretation, in case anyone may need a point of view for a better understanding of a piece of drilling and production of wells they may have an investment in.
From the number of frac stages we see that the placement of the swell packers is about normal at one per 5 casing joints from bottom and through the pay section, or at about every 210 to 240 feet and this seems to be about the norm for the area.
Using the 4 1/2" frac string for the initial flow test is a good practice as it can immediately draw off the frac fluids after the fact and quickly remove the frac water and also the invading and naturally occuring water losses from the drilling fluids (drilling mud) that seeped into the formation from drilling the well. The frac string is larger to accomodate the large volume of fluid pumped at high pressure to achieve the force to crack the rock of the producing formation and open up the cracks to place the sand into it to enhance permeability (ability to flow). When the frac is completed and frac pressure is bled off, the formation relaxes but the rock fractures are held open by the special hard sand that the frac fluid carried into the fractures. This sand can be of different strengths and grain sizes and engineers study on the properties of the formation rock to determine the size and grade of the sand. Cores cut from the verticallly drilled section are valuable for doing the study for frac design and also for reservoir engineers to calculate reservoir volumes.
Dee Three gives final "STABILIZED" flow rates at 550 bbl/day and oil grade showing a lighter oil. After the 4 day flow test it's good to see them have water cut of 10%. That 10% of water volume is restrictive to the reported flow rate. Since water is heavier than oil, the ("OVERPRESSURED") formation pressures have to put in the effort to raise that heavy and useless fluid to surface. Once this water has fully been unloaded, cleaned up, and pure oil is flowing, then it is easy to see that resistance to flow is reduced and higher flow rates of pure oil should be shown to be higher than the stabilized reported rate of 550 bbl/day.....not at all a bad thing. Now it comes to thoughts of flow line choke size and that is not reported but I would be excited to know the size of the orifice that this oil flows through. It is prudent to control the initial flow as in some cases, formation damage can occur if the well is fully open to allow maximum initial flow. As the well cleans up from frac and drilling fluids, the well can be opened up for optimum flow to recover as much oil as is safely possible. I am particularily interested in this since I heard a story from a company insider where an oil company in Montana did a JV with a native band and on the Alberta Bakken play, and drilled a successful well and flowed it to surface at 1250 bbl/day. Communications between the oil company and the natives must have failed and the natives publically reported the flow before they were informed of the secrecy or "tight hole" status of the area. For Dee Three, it is not hard to reckon that with the well cleaned and choke opened, they could concievably flow rates that are very much significantly higher than what is reported. We will have to wait and see on that idea but ultimately the true flow rates will be reported.
The production string will be by design and size does matter, and I am hopeful and optomistic that it may be 3 1/2 inch and not 2 7/8 inch tubing. Production tubing should not be too small for the potential reservoir production so that it is restrictive, and not too large that any influx of natural formation water could load up in the tubing and restrict flow or even kill the well temporarily in a worse case scenario. Smaller tubing will create turbulent or faster flow to carry any water influx while larger diameter tubing will have laminar or slower flow rates because of it's larger size and could potentially be a problem if undesirable conditions are right. The slower flow might not have the flow speed to remove any influx of water into the tubing. The offset well to KIPP was pumped and produced for over 35 years without a drop of water produced, which is a good thing, however, faster production rates could draw in produced formation water if it is there. So far I have not heard if Alberta Bakken is "wet" and I assume that it is NOT, another good thing. If the production tubing is selected to be 3 1/2 inch then it speaks loudly to an overpressured formation that is dry of natural formation water and is a large reservoir with "exceptional" flow rates. If 2 7/8 inch sized tubing is selected then excellent flow rates are possible as well.
Formation Pressure and Over Pressure: There is a pressure created by the weight of the layers of rock over the producing formation and if it follows the rules for common pressure gradients then it is considered normally pressured so the oil will have to be pumped out of the reservoir. Overpressured zones get overpressured through faulting or other conditions and will vary to the degree of overpressure, from light, moderate to extreme, depending on conditions. This formation "overpressure" will cause oil to flow unassisted to surface. When drilling, the drilling fluids have to have a density enough to overcome formation pressures to maintain control and not allow an influx into the wellbore that could create and uncontrolled flow or blowout in the worst possible case scenario. As this drilling fluid hydrostatic or dynamic pressures are against the formation rock then the water that makes up the drilling fluid will slowly weep into the formation rock. This is called "water loss" and I always thought it to be a critical piece of drilling fluid properties that needed attention and kept at a low state (I liked 5.2 to 5.6) to prevent formation damage to any sensitive production zone. Water losses can be controlled with additives that are basically starches. Part of the fluid recovery on initial production in wells will be this water loss fluid and in badly managed drilled wells, whole mud can be passed into the formation from a drilling fluid too heavy and poorly managed.
Drilling Vertically and Horizontally: In a "vertical" well, the well is more or less vertical but can be influenced by weight on bit while drilling or can deviate if formations are angled from faulting. If you ever get a chance to look down a section of a drilled well that is dry, you will see it show a pattern of corkscrewing to the left. This is from the right hand torque applied to the drill bit and then the forces of Newtons Laws of Motion taking effect to cause the corkscrew effect. This is normal and the well is still considered vertical. I mentioned it for trivia purposes and provoke thought processes. In a deviated well, the same rules apply but with a different action added. Gravity will cause the drill string to rotate and erode bottom side of the wellbore to create an oval shape or elliptical if you look at the end view of it. Mainly this is caused from the erosion created with the many tool joints (threaded connections) that are larger than drill pipe diameter so they have a tendency to create the out of gauge hole as it continually rotates in the drilling process. This mis-shaped condition is reduced using a turbine or mud motor where the pumped drilling mud rotates the bit at high speed and drill string rotation is not required.
Swell Packers: Swell packers are something new to me and have evolved for this type of horizontal drilling, I expect. They make up an integral part of the casing string so the internal diameter is the same as the casing string. The difference is that they have about a 2 meter section of rubber/ polymer surrounding and bonded to its casing wall. Have you ever had a cheap set of rubber boots, 9non neoprene) and got them oil soaked? They become swollen and distorted. Swell packers are much the same. When the casing is run to bottom it is only cemented above the pay zone to isolate the zone and to protect the environment. The swell packers sit in the wellbore, surrounded in the surrounding natural oil and the reaction causes the packers to swell from the outside of the casing and against the formation and in time, the packer expands to conform to the shape of the distorted drilled wellbore and create and effective seal at the mentioned 210 to 235 foot intervals that make up the zones to be frac stimulated. It is fraced in zones to create better fracturing of the total open horizontal and angled pay section. A fracture will take the path of least resistance so to have many zones give a better chance at full coverage of the drilled horizontal section. To do it all in one long frac operation may only offer up the same production rate as a vertical well because of the breakdown of the weakest place in the zone and then the frac taking that path of least resistance. Swell packers are simple but yet briliant for what they do and very effective. The Spring Coulee well had a failure where they could not get enough volume and pressure to the various zones with a failed process to effectively crack the desired amount of production rock.
I hope that this is of some help
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"DeeThree Exploration Ltd. says its fifth horizontal Bakken well has been drilled on the eastern portion of its Lethbridge property to a planned total depth with a horizontal lateral of approximately 970 metres in a significant porous Bakken target zone.
The horizontal lateral was successfully fracture stimulated, placing 112 tonnes of sand over 14 stages using an energized water based system.
After stimulation, the well was flowed for clean-up for four days up the 4 ½-inch frac string with final stabilizing flowing rates of approximately 550 bbls per day of 30 degrees API reservoir oil and 60 mscf per day of natural gas.
Final water cuts were approximately 10 per cent with further remaining load water from the fracture stimulation to be recovered. The well is currently shut-in to remove the frac string and install a smaller diameter production string. The well is expected to be placed onto production shortly after which it will undergo addition testing and evaluation procedures. The well will be tied-in to DeeThree’s extensive oil and gas processing infrastructure. The well is located approximately 35 kilometres from DeeThree’s original Bakken discovery well.
The company said it is very pleased with the results of its Bakken exploration and development program on the Lethbridge property to date. The company’s greatly increased understanding of the Bakken play derived from the 2011 four-well Bakken test program and its extensive 3D seismic, which has resulted in a more targeted approach to drilling on its acreage. This has resulted in DeeThree’s most significant Bakken discovery well to date."