Casing while drilling (CWD) has been around in the rotary business for only 20 to 30 years, but cable tool drillers have been using this method since about day one. In overburden and soft formations, drill and drive has been the standard method forever. When the driller reaches a competent or hard rock formation, he can seat the casing in the rock and continue without worrying about losing his hole.
With competitive price and timely delivery, KSQ Technology sincerely hope to be your supplier and partner.
In rotary drilling, there are several different reasons for CWD. Unstable formations, flowing sand and high pressure are good reasons to consider this method. The first method is to attach the bit permanently to the drill pipe. This is probably the cheapest and simplest method. You drill with the casing, and when you have reached total depth, you perforate the casing where you want production. It doesn&#;t require a special casing shoe. The downside is that you can&#;t drill below the casing without milling up the bit. No fun.
The next method is to use a special casing shoe and latch the bit into it. The driller then recovers it at the casing point, with either a wireline tool or pipe. The casing shoe will have cutters &#; usually PDC &#; on the bottom to cut a big enough annulus for the casing to pass and for cuttings to circulate out. Penetration is usually slower than in conventional drilling, but you save time by not making trips and running casing. Some models allow you to unlatch the bit and drill below the casing &#; a handy time saver. Some methods allow you to keep the bit slightly ahead, even with or slightly behind the shoe. This feature allows the driller to find the &#;sweet spot&#; that optimizes penetration. If a very straight hole is required, running the bit slightly behind the casing shoe will also give you a straighter hole.
Another CWD system uses a mud motor just behind the bit to rotate the bottom hole assembly (BHA), but not the casing. This works well in abrasive formations where casing wear is an issue. Due to the power available at the bit, this system is usually used on casing sizes larger than 7 inches. However, slim hole motors don&#;t usually have enough torque to adequately turn the bit, and penetration suffers. This system is usually used for short liners that don&#;t extend far below the casing.
In the water well world, the most common system uses a latch-in bit and the casing is rotated with the tophead. This is a fast, economical system, but consideration should be given to the wall thickness and the tool joint. Thin wall pipe or short couplings will either twist off, or the penetration will be too slow to be economical. Threads should be a premium quality and rated for drilling. On large pipe, 12 inches and up, consider welded casing. It is very reliable, and a welder is a lot cheaper than premium connection. I have done 20-inch pipe this way with good luck. Woe to you, however, if you have to trip out to change a bit.
Another consideration for the CWD method is annular clearance. You must provide enough room to circulate out cuttings. Most systems will make a big enough hole for the pipe, but remember that your annular velocity will be much higher than with drill pipe. The effect on the hole is expressed in equivalent circulating density (ECD). When the pump is not running, the pressure exerted on the bottom of the hole is depth multiplied by fluid density. As soon as you start the pump and start drilling, the pressure goes up on the formation due to friction in the annulus. With drill pipe, this is usually not a big concern because the annulus is large. With the CWD method, the annulus is much smaller and ECD goes up quickly. In shales, clays and other competent formations, this is not usually a problem. However, in incompetent formations like flowing sands, pea gravel or other porous formations, the high ECD may erode the wall cake and wash out the hole. I usually slow my pump when drilling these formations to cut ECD.
Years ago, when I was consulting, I got a call to go relieve a hand in Africa. He had been there for quite a while and was pretty burned out. They were having pressure problems and having great difficulty controlling the hole. Every time they would stop drilling to make a connection, the well would come at them and start flowing. If they weighted the mud to balance it out, every time they started the pumps, the ECD would rise, the well would drink mud, lose circulation and come at them twice as hard.
By the time I got to Africa, they had been circulating on the choke for 30 days with no end in sight. No wonder the other hand was burned out. I relieved the other hand, got him on a plane home and started trying to figure out how to control the well. I quickly realized there was no way. I talked to the engineers who, although they could speak English, preferred to have technical meetings in French. My high school French is pretty rusty, but I finally convinced them to abandon the well, move over and use a different method: casing drilling! We never did get the hole under control well enough to trip out, so we ended up cementing the entire BHA, bit, motor, collars and all, and shooting the pipe up higher.
We knew right where the pressure was, so we were ready when we got to that depth on the offset well. Since there had been no problems higher up in the hole, we drilled with conventional methods until we got near the top of the trouble zone. As we drilled into the pressure zone, the well started to flow slightly, so we increased the mud weight a little. Since we already knew what the formation would stand, we got pretty good at it. When we would drill a joint down, we would circulate and get the mud as perfect as we could. Before we made our connections, we would always have a doghouse meeting to go over everybody&#;s job on the connection. Got pretty good at it, too. It was a good crew!
It was kind of spooky, because every time we made a connection, the well would start to flow. It wasn&#;t serious, but it was enough to get everybody&#;s attention. By the time we got the pumps back on and resumed drilling, we had gained quite a bit in the pits and had to recondition the mud. It was a slow process. The front office had told us how deep they wanted the casing set, and we were getting pretty good at making record-time connections and continuing to drill. By the time we got deep enough, we had it down pat. I called Aberdeen and asked the head engineer if we could go a little deeper to assure a good casing seal. He said, &#;Well, it looks like you are doing it right, so go ahead.&#; I made 300 more feet into a good, competent formation before we figured we were deep enough to continue the well. We cemented the casing almost back to the drill pipe, and shot it off with a wireline severing tool.
While I had drilled with the CWD method before, I had never drilled anything this deep or complicated. The French engineers thanked me and sent me home with several bottles of French champagne!
Point is: This is a method to keep in your toolbox until you need it. Might save a well, and make some money along the way!
For more Wayne Nash columns, visit www.thedriller.com/wayne.
I-Introduction
An oil and gas well is drilled in sections from the surface to the production zone. It is not possible to drill the well in one section due to the difference in formations properties. Each section of formation, after being drilled, has to be sealed off by running a steel pipe called casing. The annular space between the casing and the borehole is filled with cement ( Click Here ). The casing string is consisted of pipe joints, of approximately 40ft in length with threaded connections.
There are several loads which have to be considered when designing a casing string. Casing can be exposed to different loads while installation, drilling next section and producing from the well. The loads depend on many factors: formation pore pressure, formation fracture gradient, temperature profile and also the fluid encountered while drilling through the production zone.
Fig 01- Conventional Casing Program
Casing has many functions and can be summarized as follows:
- Provide a support for fractured, weak and vulnerable formations.
- Prevent contamination of fresh water zones
- Isolate abnormal pressure zones and also lost circulation zones
- Provide passage for production fluids. In general, production operations are performed through tubing which is run inside the casing.
- Provide support for surface equipment (blow out preventer and production tree)
- Allow an adequate means for installing artificial lift equipment for production
- Offer a known borehole diameter in order to perform further operations
It is the first and largest casing to be run. It is generally set at 100 ft below the ground level. The main function of setting the conductor pipe is sealing off the unconsolidated formations which are near the surface. These formations can be easily washed out with continuous mud circulation; also they are characterized with low fracture gradient which can be exceeded by the hydrostatic pressure generated by the drilling fluids.
The function of this type of casing is sealing off the fresh water zones and providing a support for the blowout preventer (BOP). The setting depth of this casing has to be accurately designed in areas where high pressure is expected. If the surface casing is set higher than planned or the setting depth is underestimated, the formation at casing shoe cannot resist to the pressure exerted while circulating gas influx which can occurs during drilling the next section.
Many troublesome formations can be encountered during drilling operations till getting to the production zone. These troublesome formations have to be isolated by what it is called intermediate casing. The number of strings run as intermediate casing depends on the faced problems such as: lost circulation zones, unstable shale, squeezing salts and abnormally pressured zones.
It can be set above the production zone or run through it. The main function is to isolate production zone from the other formation such as water bearing sands. This type of casing is also used as a conduit for production tubing.
Contrarily to the other types of casing strings which are hanged at the surface, the liners are suspended inside the previous casing string by the liner hangers. The liner hangers consisted of slips which can be activated hydraulically or mechanically. Slips grip inside the previous string in order to support the weight of the liner.
Running a liner has many advantages:
- Significant cost reduction due to shorter strings
- Drill pipe is used to run the liner which leads to less rig time
- Liner can be rotated while cementing the hole which can improve the quality of cement.
In some cases, a casing of the same diameter can be run above the liner and connect it to the top of it which lead to extend the liner to the surface. The additional casing string is called tie-back string. The tie-back string is run to protect the previous casing from pressures which can occur when starting production.
If the liner is used to isolate the troublesome zones is called drilling liner rather than intermediate casing.
Fig 02- Types of Casing
Once the casing size and setting depth are selected, the loads which are exerted on the casing string will be calculated. According to these loads the casing properties are selected. Casing is classified in terms of outer diameter or size, weight, grade and the type of the connection.
The size of the casing or also called the outer diameter of the casing joint varies from 4.5'' to 36''. The string which has less than 4.5'' is called the tubing rather than casing. The casing sizes are limited to standard sizes which can be available in the market.
The casing joint is characterized by the casing weight which is given as weight per foot. The API has designed and limited the internal diameter of a casing joint, but this diameter can vary slightly when manufacturing the joint of casing. A minimum guaranteed internal diameter is called drift diameter which is important when planning for further operations (ex: the drilling bit which will be run to drill the next section has to be less than the drift diameter).
The casing length is standardized by the API into three ranges:
- Range 1: 22ft
- Range 2: 31ft
- Range 3: 42ft
The most common range is range 2, but it is impossible to manufacture the joint of casing in a precise length, so it is important to measure each joint of casing when receiving the casing on rig site, and record the total length on tally sheet. The measure is taken from the top of the joint to the end of the pin. There are shorter joints called pup joints which are used to adjust casing when running in the hole.
During casing manufacturing process; a variety of treatment processes can be performed; and according to the process which is applied on the steel, the joint of casing take its physical properties. The API has classified the casing in '' grades ". Each grade is represented by a letter and a number. The letter is for the chemical composition and the number is for the minimum yield strength.
The casing joints are connected together using a threaded connection. These threaded connections are classified as: API, gas-tight, metal to metal seal and premium.
In the case of API, the joints of casing are threaded externally at each end, and then the joints are connected by couplings which are internally threaded. At the rig site, the casing is delivered with installed couplings. The standard types of threads are:
- Short thread connection STC
- Long thread connection LTC
- Buttress thread connection BTC
Both the STC and LTC have 08 threads per inch, but the LTC has longer coupling and provides better strength and sealing properties.
The API connections are not the only types of threads, there are other manufacturers which deliver different threads like: Hydril, vallourec and Mannesman. The connections are designed to contain high level of gas pressure.
For better sealing performance when running a casing string, some practices are followed on the rig site:
Contact us to discuss your requirements of Casing Drilling System. Our experienced sales team can help you identify the options that best suit your needs.
- Apply the right make-up torque determined by the manufacturer
- Clean the threads before running the casing
- Use the right thread and check if the joints have the same type of thread
- Good handling procedures on the rig site
The casing string has to be pressure tested before drilling the next section for pressure integrity.
For casing design, there are three main loads which have to be considered:
- The yield strength
- Collapse pressure
- Burst pressure
Many scenarios have to be imagined to design the casing in realistic way for risk assessment, integrity and also for costing.
The yield strength is defined as tensile stress which produces the 0.5% elongation per unit length of casing specimen. This value varies according to the steel alloy used to make the casing joint.
Couplings have also their yield strength which can be higher or lower than the main body yield strength. The manufacturer supplies data for both: main body and the coupling.
It is defined as the maximum external force which crushes the casing. This can happens when the pressure behind the casing is higher than the pressure inside the casing. The external pressure tends to crush the joint of casing inwards.
The collapse pressure can differ according to the situation. Designing for an empty casing, getting fluid influx, or movable salt which can flow toward the casing gives different collapse pressures. For this reason it is important to consider any situation which can be faced during operations.
It is tested that the cementing improves the collapse resistance of casing. Cementing in many cases is important for well integrity. Getting voids between formation and casing can allow for example to salt to move freely toward the casing and collapse it.
The casing can rupture when internal pressure is higher than the external pressure. The resultant pressure tends to deform the joint of casing outwards. The burst pressure is higher if gas comes from high pressurized formation. If the gas is allowed to migrate to surface in a closed well, the pressure will be higher because gas cannot expend and the pressure will not decrease which adds more hydrostatic pressure.
Beside these loadings mentioned above, the casing has also to resist to other types of loadings which have to be considered at designing stage:
- Bending in deviated wells
- Temperature in high temperatures wells
- Corrosion in presence if hydrogen sulfide H2S and Carbon Dioxide CO2
- Biaxial loading when getting loading combination
Table 01- Example of Casing Strength Properties
The string of casing is fitted with several accessories before running in the hole.
It is used to facilitate running the casing in the hole. It is set at the first run joint of casing. The most common casing shoes are: the guide shoe and the float shoe.
The difference is that the float shoe is fitted with a float valve or non-return valve. This valve allows the fluids the flow outside the casing and it stops them to flow back into the casing while the circulation or pumping is ceased.
Fig 04- Casing Shoe
It is a sub which has the same diameter of the casing. It is placed between the two first joints. It is fitted with a float valve to prevent fluids to flow back into the casing while running. The float collar is also used as seat for cement plugs.
The float collar also prevents cement U-tubing effect before the cement strengthens and hardens in the annulus.
Fig 06- Float Collar
They are placed around the casing joints. They are held in their position by using stop collars. The Centralizers have some advantages:
- Remaining the casing in center position in the borehole to allow preforming a successful cementing job.
- Minimizing contact area between the casing and borehole wall
But also it has to mention that centralizers can increase the drag which can affect running the casing and generates problems before reaching the bottom of the hole.
Fig 07- Casing Centralizers
Casing hangers and wellheads
The casing string is suspended at the wellhead. It is consisted of a series of spools set one on top of the other. The wellhead has different functions:
- Suspending the casing weight
- Providing an interface between the BOP stack and the casing string
- Sealing off the annulus between the different casing strings
- Allowing the access to the casing annulus
The casing is hanged using the casing hanger which sets inside the casing spool. The hangers should be designed to hold the weight of the casing and seal off between the casing hanger and the spool.
There are two types of casing hangers:
- Mandrel type: in this case, the hanger is screwed on the top of casing string. When the casing shoe reaches the casing seat depth, the hanger should land on the casing housing. In some cases, pup joints of casing are needed to land the casing hanger at the shoulders into the spool. Using this type of casing can be risky when reaching the bottom of the wellbore is a difficult issue.
- Slip type: this type is wrapped around the body of the casing. Setting at the casing spool is performed by lowering the hangers. The suspension is performed by slips machined at inner side of the hangers. These slips set automatically when the casing is lowered. This type is used when the casing cannot reach the bottom and spacing out the string will be difficult.
Fig 07- FMC Casing Hanger
Subscribe to receive free updates:
Delivered by FeedBurner
If you want to learn more, please visit our website Drilling Accessories Suppliers.