The hoisting system is a large pulley system which is used to lower and raise equipment into and out of the well. In particular, the hoisting system is used to raise and lower the drillstring and casing into and out of the well. The components parts of the hoisting system are shown in Figure 3. The drawworks consists of a large revolving drum, around which a wire rope (drilling line) is spooled. The drum of the drawworks is connected to an electric motor and gearing system. The driller controls the drawworks with a clutch and gearing system when lifting equipment out of the well and a brake (friction and electric) when running equipment into the well. The drilling line is threaded (reeved) over a set of sheaves in the top of the derrick, known as the crown block and down to another set of sheaves known as the travelling block. A large hook with a snap-shut locking device is suspended from the travelling block. This hook is used to suspend the drillstring. A set of clamps, known as the elevators, used when running, or pulling, the drillstring or casing into or out of the hole, are also connected to the travelling block.
drilling rig hoisting system

Having reeved the drilling line around the crown block and travelling block, one end of the drilling line is secured to an anchor point somewhere below the rig floor.Since this line does not move it is called the deadline. The other end of the drilling line is wound onto the drawworks and is called the fastline. The drilling line is usually reeved around the blocks several times. The tensile strength of the drilling line and the number of times it is reeved through the blocks will depend on the load which must be supported by the hoisting system. It can be seen from Figure 3 that the tensile load (lbs.) on the drilling line, and therefore on the fast line, Ff and dead line Fd in a frictionless system can be determined from the total load supported by the drilling lines, W (lbs.) and the number of lines, N reeved around the crown and travelling block:

 

Most drilling rigs are required to operate in remote locations where a power supply is not available. They must therefore have a method of generating the electrical power which is used to operate the systems mentioned above. The electrical power generators are driven by diesel powered internal combustion engines (prime movers). Electricity is then supplied to electric motors connected to the drawworks, rotary table and mud pumps (Figure 2). The rig may have, depending on its size and capacity, up to 4 prime movers, delivering more than 3000 horsepower. Horsepower (hp) is an old, but still widely used, unit of power in the drilling industry.

rig power system

Older rigs used steam power and mechanical transmission systems but modern drilling rigs use electric transmission since it enables the driller to apply power more smoothly, thereby avoiding shock and vibration. The drawworks and the mud pumps are the major users of power on the rig, although they are not generally working at the same time.

There are many individual pieces of equipment on a rotary drilling rig (Figure 1). These individual pieces of equipment can however be grouped together into six sub-systems. These systems are: the power system; the hoisting system; the circulating system; the rotary system; the well control system and the well monitoring system. Although the pieces of equipment associated with these systems will vary in design, these systems will be found on all drilling rigs. The equipment discussed below will be found on both land-based and offshore drilling rigs.

rotary drilling rig

About 25% of the world’s oil and gas is currently being produced from offshore fields (e.g. North Sea, Gulf of Mexico). Although the same principles of rotary drilling used onshore are also used offshore there are certain modifications to procedures and equipment which are necessary to cope with a more hostile environment.

In the North Sea, exploration wells are drilled from a jack-up (Figure 6) or a semi-submersible (Figure 7) drilling rig. A jack-up has retractable legs which can be lowered down to the seabed. The legs support the drilling rig and keep the rig in position (Figure 6). Such rigs are generally designed for water depths of up to 350 ft water depth. A semi-submersible rig is not bottom supported but is designed to float (such rigs are commonly called “floaters”). Semi-submersibles can operate in water depths of up to 3500 ft. (Figure 7). In very deep waters (up to 7500 ft) drillships (Figure 8) are used to drill the well. Since the position of floating drilling rigs is constantly changing relative to the seabed special equipment must be used to connect the rig to the seabed and to allow drilling to proceed.

Jack Up Rig

Semi Submersible Rig

If the exploration wells are successful the field may be developed by installing large fixed platforms from which deviated wells are drilled (Figure 9). There may be up to 40 such wells drilled from one platform to cover an entire oilfield. For the very large fields in the North Sea (e.g. Forties, Brent) several platforms may be required. These deviated wells may have horizontal displacements of 10,000 ft and reach an inclination of 70 degrees or more. For smaller fields a fixed platform may not be economically feasible and alternative methods must be used (e.g. floating production system on the Balmoral field). Once the development wells have been drilled the rig still has a lot of work to do. Some wells may require maintenance (workovers) or sidetracks to intersect another part of the reservoir (re-drill). Some wells may be converted from producers to gas injectors or water injectors.

Drill Ship

Fix Platform Rig

A well drilled from an offshore rig is much more expensive than a land well drilled to the same depth. The increased cost can be attributed to several factors, e.g. specially designed rigs, subsea equipment, loss of time due to bad weather, expensive transport costs (e.g. helicopters, supply boats). A typical North Sea well drilled from a fixed platform may cost around $10 million. Since the daily cost of hiring an offshore rig is very high, operating companies are very anxious to reduce the drilling time and thus cut the cost of the well.

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Before a drilling programme is approved it must contain an estimate of the overall costs involved. When drilling in a completely new area with no previous drilling data available the well cost can only be a rough approximation. In most cases however, some previous well data is available and a reasonable approximation can be made.

table1

A typical cost distribution for a North sea Well is Shown in Table 2. Some costs are related to time and are therefore called time-related costs (e.g. drilling contract, transport, accommodation). Many of the consumable items (e.g. casing, cement) are related to depth and are therefore often called depth-related costs. These costs can be estimated from the drilling programme, which gives the lengths or volumes required. Some of the consumable items such as the wellhead will be a fixed cost. The specialised services (e.g. perforating) will be a charged for on the basis of a service contract which will have been agreed before the service is provided. The pricelist associated with this contract will be a function of both time and depth and the payment for the service will be made when the operation has been completed. For wells drilled from the same rig under similar conditions (e.g. platform drilling) the main factor in determining the cost is the depth, and hence the number of days the well is expected to take. Figure 10 shows a plot of depth against days for wells drilled from a North Sea platform. It is interesting to note that of the total time spent drilling a well less than half is spent actually rotating on bottom (Table 3).

table23

More sophisticated methods of estimating well costs are available through specially designed computer programmes. Whatever method is used to produce a total cost some allowance must be made for unforeseen problems. When the estimate has been worked out it is submitted to the company management for approval. This is usually known as an AFE (authority for expenditure). Funds are then made available to finance the drilling of the well within a certain budget. When a well exceeds its allocated funds a supplementary AFE must be raised to cover the extra costs.

drillingtime-depth chart

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If the well is to be used for long term production, equipment which will allow the controlled fl ow of the hydrocarbons must be installed in the well. In most cases the first step in this operation is to run and cement production casing (9 5/8″ O.D.) across the oil producing zone. A string of pipe, known as tubing (4 1/2″ O.D.), through which the hydrocarbons will flow is then run inside this casing string. The production tubing, unlike the production casing, can be pulled from the well if it develops a leak or corrodes. The annulus between the production casing and the production tubing is sealed off by a device known as a packer. This device is run on the bottom of the tubing and is set in place by hydraulic pressure or mechanical manipulation of the tubing string.

When the packer is positioned just above the pay zone its rubber seals are expanded to seal off the annulus between the tubing and the 9 5/8″ casing (Figure 5). The BOP’s are then removed and a set of valves ( Christmas Tree ) is installed on the top of the wellhead. The Xmas tress is used to control the fl ow of oil once it reaches the surface. To initiate production, the production casing is “ perforated ” by explosive charges run down the tubing on wireline and positioned adjacent to the pay zone. Holes are then shot through the casing and cement into the formation. The hydrocarbons flow into the wellbore and up the tubing to the surface.

Completing the Well

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When the BOP has been re-installed and pressure tested a 12 1/4″ hole is drilled through the oil bearing reservoir. Whilst drilling through this formation oil will be visible on the cuttings being brought to surface by the drilling fluid. If gas is present in the formation it will also be brought to surface by the drilling fluid and detected by gas detectors placed above the mud flowline connected to the top of the BOP stack. If oil or gas is detected the formation will be evaluated more fully.

The drill string is pulled out and tools which can measure for instance: the electrical resistance of the fluids in the rock (indicating the presence of water or hydrocarbons); the bulk density of the rock (indicating the porosity of the rocks); or the natural radioactive emissions from the rock (indicating the presence of non-porous shales or porous sands) are run in hole. These tools are run on conductive cable called electric wireline , so that the measurements can be transmitted and plotted (against depth) almost immediately at surface. These plots are called Petrophysical logs and the tools are therefore called wireline logging tools .

In some cases, it may be desireable to retrieve a large cylindrical sample of the rock known as a core . In order to do this the conventional bit must be pulled from the bore hole when the conventional drill bit is about to enter the oil-bearing sand. A donut shaped bit is then attached a special large diameter pipe known as a core barrel is run in hole on the drill pipe.

This coring assembly allows the core to be cut from the rock and retrieved. Porosity and permeability measurements can be conducted on this core sample in the laboratory. In some cases tools will be run in the hole which will allow the hydrocarbons in the sand to fl ow to surface in a controlled manner. These tools allow the fluid to flow in much the same way as it would when the well is on production. Since the produced fl uid is allowed to fl ow through the drillstring or, as it is sometimes called, the drilling string, this test is termed a drill-stem test or DST .

If all the indications from these tests are good then the oil company will decide to complete the well . If the tests are negative or show only slight indications of oil, the well will be abandoned.

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Once the cement has set hard, a large spool called a wellhead housing is attached to the top of the 20” casing. This wellhead housing is used to support the weight of subsequent casing strings and the annular valves known as the Blowout prevention (BOP) stack which must be placed on top of the casing before the next hole section is drilled.

Since it is possible that formations containing fluids under high pressure will be encountered whilst drilling the next (17 1/2”) hole section a set of valves, known as a Blowout prevention (BOP) stack, is generally fitted to the wellhead before the 17 1/2” hole section is started. If high pressure fluids are encountered they will displace the drilling mud and, if the BOP stack were not in place, would fl ow in an uncontrolled manner to surface. This uncontrolled flow of hydrocarbons is termed a Blowout and hence the title Blowout Preventers (BOP’s) . The BOP valves are designed to close around the drillpipe, sealing off the annular space between the drillpipe and the casing. These BOPS have a large I.D. so that all of the necessary drilling tools can be run in hole.

When the BOP’s have been installed and pressure tested, a 17 1/2″ hole is drilled down to 6000 ft. Once this depth has been reached the troublesome formations in the 17 1/2″ hole are isolated behind another string of casing (13 5/8″ intermediate casing). This casing is run into the hole in the same way as the 20” casing and is supported by the 20” wellhead housing whilst it is cemented in place.

When the cement has set hard the BOP stack is removed and a wellhead spool is mounted on top of the wellhead housing. The wellhead spool performs the same function as a wellhead housing except that the wellhead spool has a spool connection on its upper and lower end whereas the wellhead housing has a threaded or welded connection on its lower end and a spool connection on its upper end. This wellhead spool supports the weight of the next string of casing and the BOP stack which is required for the next hole section.

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The first hole section is drilled with a drill bit, which has a smaller diameter than the inner diameter ( I.D. ) of the conductor. Since the I.D. of the conductor is approximately 28”, a 26” diameter bit is generally used for this hole section. This 26″ hole will be drilled down through the unconsolidated formations, near surface, to approximately 2000′.

If possible, the entire well, from surface to the reservoir would be drilled in one hole section. However, this is generally not possible because of geological and formation pressure problems which are encountered whilst drilling. The well is therefore drilled in sections, with casing being used to isolate the problem formations once they have been penetrated. This means however that the wellbore diameter gets smaller and smaller as the well goes deeper and deeper. The drilling engineer must assess the risk of encountering these problems, on the basis of the geological and formation pressure information provided by the geologists and reservoir engineers, and drilling experience in the area. The well will then be designed such that the dimensions of the borehole that penetrates the reservoir, and the casing that is set across the reservoir, will allow the well to be produced in the most effi cient manner possible. In the case of an exploration well the fi nal borehole diameter must be large enough to allow the reservoir to be fully evaluated.

Whilst drilling the 26” hole, drilling fluid ( mud ) is circulated down the drill pipe, across the face of the drillbit, and up the annulus between the drillpipe and the bore hole, carrying the drilled cuttings from the face of the bit to surface. At surface the cuttings are removed from the mud before it is circulated back down the drillpipe, to collect more cuttings.

When the drill bit reaches approximately 2000’ the drill string is pulled out of the hole and another string of pipe ( surface casing ) is run into the hole. This casing, which is generally 20″ O.D., is delivered to the rig in 40ft lengths (joints) with threaded connections at either end of each joint. The casing is lowered into the hole, joint by joint, until it reaches the bottom of the hole. Cement slurry is then pumped into the annular space between the casing and the bore hole. This cement sheath acts as a seal between the casing and the borehole, preventing cavings from falling down through the annular space between the casing and hole, into the subsequent hole and/or fluids fl owing from the next hole section up into this annular space.

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The first stage in the operation is to drive a large diameter pipe to a depth of approximately 100ft below ground level using a truck mounted pile-driver. This pipe (usually called casing or, in the case of the fi rst pipe installed, the conductor ) is installed to prevent the unconsolidated surface formations from collapsing whilst drilling deeper. Once this conductor, which typically has an outside diameter ( O.D. ) of 30” is in place the full sized drilling rig is brought onto the site and set up over the conductor, and preparations are made for the next stage of the operation.

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