Coiled Tubing Drilling
In addition to jointed pipe drilling, coiled tubing (see Chapter 18 for Coiled Tubing quipment and Techniques) can also be used for drilling and milling in some applications. Coiled tubing offers several advantages and a few current disadvantages that should be explored for their potential in completions and workovers. One of the best uses of coiled tubing drilling may be in combination with underbalanced drilling “where the well is allowed to flow during the drilling operation.”The simplest coiled tubing drilling bottomhole assembly (BHA) includes a bit, mud motor, stabilizers or collars, the connector and the coil. The abilities of coiled tubing for drilling include a continuously fed fluid transfer mechanism (the coil) with no tool joints. This one feature allows the smooth external wall that can be sealed very easily at the surface. Fluids returning from downhole up the annular area are vented under pressure to surface separation equipment and small kicks and gases can be handled easily.
In many of the first examples of coiled tubing milling and drilling, the mud motors which provide turning ability at bit often stalled or stopped turning because of excess loads placed on the bits from either the string or the bottomhole assembly. This reoccurring motor stalling problem resulted in very slow penetration. Motor stalls typically occur when downward forces (weight and force) at the bit are greater than the ability of the motor to turn the bit. There are a number of reasons for motor stalls.
1. Too aggressive a bit or mill design will require excessive power to turn. Less aggressive (smaller teeth) milled and bits are easier to turn, although they may drill some materials slightly slower.
2. Coiled tubing milling and drilling typically uses smaller motors with less torque. The smaller motor design utilizes very small clearances and small loaders and stators in the mud motors.
3. In deviated wells, trying to apply force on coiled tubing from the surface may result in first sinusoidal and then helical buckling. When buckling occurs, regardless of its location in the wellbore, the stored energy will try to work its way either up or down and add an extra force against the bit the surface unit.
4. The injector feed control at the surface is often a major source of the problem. The injector is a source of all upward and downward force exclusive of drill collars and other weight. Ideally, the feed of the coiled tubing through the injector should be no faster than the penetration through the bit or mill. If too much tubing runs through the injector at any time, the total force on the bit increases and a motor stall may occur. For best results, very slow speed or micro movement of the injector head should be possible in any unit used for coiled tubing drilling.
Underbalanced Drilling
Slimholes
Slimhole drilling has become a popular concept in recent years. Although smaller diameter holes are theoretically cheaper to drill because less formation is actually removed, they are not always a cheaper hole to drill. Cost of drilling involves not only the time to cut through a part of the formation, but also involves the use of existing (paid for) versus new and smaller equipment, and several other factors including pressure control and the cost of the completion. Many times it has been found that drilling a smaller hole actually costs more than drilling a traditional hole where costs of normal sized equipments was very cheap in comparison to special ordered newer and smaller equipment. Pressure control during drilling or workovers in small wellbores is often very difficult. An example, shown in Chapter 15 on workover fluids and control, shows that the volume of a 1 bbl kick in a small
diameter (3-3/4 in. hole) versus a large diameter hole (9-112 in.) may result in several hundred psi difference just from the volume of the hole filled by the 1 bbl kick. When drilling or working over holes with small diameters, accurate trip tanks and a functional alarm system must be used to minimize danger from kicks.
Initial Completion Design
Selecting the Pay Zone
Selecting the pay and deciding where to place the wellbore are two of the most important pieces of engineering that most occur in the completion process. Many rocks from shales to fractured granites contain hydrocarbons, but, not every rock type or reservoir can qualify as a pay zone. Selection of the pay breaks down into several basic considerations:
1-Prospect development economics,
2-porosity and permeability requirements,
3-hydrocarbon type and saturation requirements,
4-recoverable hydrocarbon volumes (by primary, secondary and tertiary methods),
5-pressure support,
6-reservoir stability,
7-recognition of compartmentalization,
8-availability of technology to cost effectively produce the reserves,
9-ability to plug and abandon the reservoir,
10-environmental and other risks.
The economics of a project depend simply on whether enough money can be made from sale of the productive hydrocarbons in a limited amount of time to offset the total costs of the project. The associated cost of the project may include a variety of finding, development, production and abandonment costs. Among these costs are: prospect leasing, field development, field operation, royalties, interests on the money used,
profit, risks, plug and abandonment costs and contingency funds for all matters problems such as blowouts and cleanup operations. Substantial deposits of crude oil and gas are known in many parts of the world, bu cannot be currently produced because the production rates cannot offset the cost of development and operation. Every year many of these (outer limit) deposits are being brought on-line as producing reservoirs as technology is being developed or the cost of development drops through other factors. Even the cost of
Deepwater developments, for example, which can be in the hundreds of millions or even billions of dollars can be economic if risk can be reduced and if the production rate from the wells is high. Every project from the shallowest stripper well at 2 bpd to the 100 mmscf/d or 30,000 bpd oil wells must be judged by some risks versus cost recovery and profit factor.
Porosity and permeability are the reservoir storage and pathway of flowing fluids. Porosity is the void space between the grains in which fluids can be stored. Permeability is a measurement of the ability of fluids to flow through the formation. Rocksuch as shales and chalk, for example, may have extremely high porosities approaching 30-40 percent, but the porosity is not linked together, thus the permeability is very low. On the other hand, naturally fractured formations may have extremely high permeabilities approaching tens of darcies
in some cases, but have very low porosity, often only 4-6 percent. The amount of porosity and permeability necessary for a project depends on the production rate needs, although, operations such as hydraulic fracturing can increase the production rate of a well by a factor of 2 to 10 or more. Fracturing alone may not make the project economic. The economics of a project are such that every factor must be weighed in turn in the economic justification and critical factors, such as hydrocarbon storage and the permeable pathway, must be available before even a huge reservoir with billions of barrels of oil can be made productive. In reservoir selection, often times a porosity or permeability cutoff is used for pay versus nonpay identification. Recognition of this level from porosity logs and flow tests are often critical in establishing minimum pay requirements.
Hydrocarbon type and saturation determine the amount of hydrocarbons that may occupy the pore space of a reservoir. Many factors such as moveable versus irreducible saturations and changing factors such as relative permeability can make the saturation and permeability values “moving targets.” There are no set minimum values for hydrocarbon saturation, however, the best parts of the reservoir will usually have the higher values of hydrocarbon saturation. Saturation of water may also be a key in pay identification. Extremely high saturations of water may indicate hydrocarbon depletion or movement of an aquifer into the
Pay.
The recoverable hydrocarbon volumes are usually calculated form the measured values of porosity and saturation. Oil in place quantities do not indicate that all of that oil can be recovered. The porosity of a formation varies from very large pores to very small pores and the oil in very small pores often will not flow from the small capillaries even under very high depletion pressures. How much oil will flow from a rock is dependent on the size of the pore spaces, the oil saturation and type and the amount of energy available to push the
oil towards the wellbore. Recoverable hydrocarbon estimates may vary many percentage points from what reality shows later on. The differences many times are in how well the pressure supports the drive mechanism in producing the fluids.
The pressures in the reservoir dictate how much fluid will ultimately be recovered. Many different types of pressure supports are available. The typical pressure support mechanisms include bottom and edgewater drives, gas cap drives, volumetric depletion and other pressure sources such as reservoir compaction and other factors. Each of these pressure support mechanisms has advantages and disadvantages to deciding recovery in a reservoir. Among the most effective types of reservoir pressure support are the bottom and
edgewater drives. These systems may maintain pressure at initial values clear to the end of the project. The problems with them is they may produce large amounts of water along with the oil. Volumetric depletion is usually found in a sealed reservoir and then the reservoir may deplete without producing any water. The recovery, however, from this types of reservoir is extremely low, since reservoir energy bleeds off very quickly. Pressure support can be added, in some cases, by the use of water floods, gas repressurization or
other types of pressure maintenance such as tertiary floods. When factors such as bottomwater or edgewater drive are recognized early, the location of the wellbores can be selected to take advantage of flow paths of the drive fluids and recoveries can be enhanced.
Reservoir stability is an issue which may effect the initial completion or repairs or recompletions throughout the life of the reservoir. Many geologically young formations lack sufficient strength for formation coherency during all phases of production. Recognition of this stability issue is usually easy because of rapid drilling rates, sand strength issues in the wellbore or other factors. The decision on adding a stabilizing completion
is usually made after consideration from initial flow tests and other factors. The most common methods of include resign consolidation or production rate restriction to avoid sanding. Recognition of compartmentalization is probably one of the most important factors in the initial design of well completions for a project. Compartmentalization is the division of a reservoir into partial or fully pressure isolated compartments by faults, permeability or porosity pinchouts, folding, shale streaks, barriers or other factors. When compartmentalization is recognized, the location and type of wellbores can be selected to
efficiently drain the compartments and to take advantage of fluid flow patterns within the reservoir. Many of the failures of even large fields can be traced to a failure to recognize compartmentalization during the early development steps in the reservoir. The availability of technology to produce the reserves is an area which keeps the oil industry active in
research and development. Technology such as water flooding, hydraulic fracturing, artificial lift, cold flow of heavy oils, coal degassification and many other projects have increased the worlds recoverable hydrocarbons and continue to be a critical part of meeting the worlds energy needs. When the reservoir flow patterns and other factors are understood, technology can often be developed within a moderate time frame to meet needs in specialized reservoirs. The ability to produce hydrocarbons should never outstrip the ability to control the flow or the ability to plug an abandoned reservoir. Plug and abandonment intentions must take into account that the reservoir should be left in as good a condition as possible for potential tertiary operations that may recover even more fluids. Plug and abandonment costs can be a significant amount of the project cost. Offshore plug and abandonment of fields may reach over 100 million dollars. There are many associated risks, both political and environmental in developing and producing a hydrocarbon depositry. These risks must be taken into account during the economic justification for the reservoir and should offer as good a solution as is possible to the legitimate concerns posed in any situation. Once the values are known, selection of the pay can begin. The selection process uses a number of pieces of information gathered by electronics and other factors.
The objectives in this chapter will be to establish ground rules about what general completion mechanisms have the best fit to the reservoir potential.
Completion design is a function of reservoir characteristics. The problem is that reservoir data, particularly the design sensitive data such as permeability, porosity, saturations, pressure, barriers and longevity, are only fully available after most of the wells in the field have been drilled, completed and tested. In many cases, after initial drilling and completion, reservoir barriers are finally recognized and extreme redrilling or stimulations are needed to process the reservoir. The key to a good initial completion is to collect and assess the data at the earliest possible time, to allow the best early choice of completion.
Successful completions recognize the flow characteristics of the reservoir. There are a number of completion possibilities; each with a limited “fit” to the reservoir properties. The following is a general listing of the completion types with a few of the reservoir variables. The numbers for most variables are typical but only general estimates.
Vertical well
open hole
natural completion
High permeability (Kh 2 10 md for oil, 1 1 md for gas) stable formation (no movement or spalling) no bottom or edge water drives low KJK, c 0.5 KH) (or deviated wells not considered possible) no fracture plannedlpossible, no limits on surface reservoir accesslaminations not “frequent.”
Special considerations:
1. Steeply tilting pay: examine hydrocarbon and water fluid flow path to wellbore including effects of K, and KH. Also investigate fracture growth and path. May choose uphill horizontal wellbore to go after “attic” or up-dip reserves that are above vertical well contact.2. High permeability “streaks”: The size and permeability contrast to the reservoir location with respect to oil/water contact can significantly affect production or water break through. Orientation of the well path or decision to frac may be affected.
3. Salt or techtonic forces: Salt Ylow” may produce extreme loads on casing. The normal approach requires concentric dual casing strings with annular spaces cemented. Techtonic forces, and some horizontal collapse forces may create point loads on the casing which are better handled by extremely heavy wall casing strings.
4. Sweep/Floods: Well placement to process a reservoir uses the permeability pathways for best advantage. Wellbore location, orientation and deviation may be influenced.
5. Fluid Requirements: Heavy oil, scaling, organic precipitation, chronic emulsions, bubble and dew points and other special requirements may make completion compromises or redesigns necessary.
6. Multiple Zones: multiple zones completions and independent completions may be required by pressure, fluid or royalty owners.
7. The initial design is the starting place for the completion, however, it should never be construed to be unchangable. Flexibility is required for any completion to take advantage of information that can be obtained from drilling or other sources.
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