Chapter 2: Casing Design lec ( 6 )

Open Hole Completions

The first decision on casing the pay zone is not of size or weight but whether or not to run casing at all. Open hole completions represent the simplest type of completions and have some very useful traits. They also present some problems. An open hole or barefoot completion is usually made by drilling to the top of the pay, then running and cementing casing. After these operations, the pay is drilled with a nondamaging fluid. Since the other formations are behind pipe, the drilling fluid overbalance is only that needed to control the reservoir pressure. This creates less damage. Open hole completions have the largest possible formation contact with the wellbore, allowing injection or production with every part of the contacted interval. The effect of the open hole on stimulated operations depends on the type of job. Fracturing operations are often easier in the open hole than through perforations by less possibility of perforation screenouts, but the perforations may make the zone easier to break down since a crack (the perforation) has already been placed. Matrix acidizing can more evenly contact the entire zone in an open hole but is more difficult to direct by straddle packer than in a cased hole. Hydraulic jetting is most effective in the open hole. Productivity of open hole gravel packs, especially the underreamed open holes are usually much higher than cased hole gravel packs. Why then, are casing strings even used? Part of the answer is in formation (wellbore) stability concerns and part is unfamiliarity with completing and producing the open hole completions. A decision must be reached on the merits of the completions on the pay in question. If the pay is prone to brittle
failures during production that leads to fill, most operators choose to case and cement. In areas of water coning or zone conformance problems, casing may make isolation of middle or top zones possible. With the advent of improved inflatable packers and matrix sealants, however, isolation is also possible in open holes, although wellbore diameter may be severely restricted.

Cased Hole Completions

A casing string is run to prevent the collapse of the wellbore and to act in concert with the cement sheath to isolate and separate the productive formations. The size of the casing is optimized on the expected productivity of the well and must be designed to withstand the internal and external pressures associated with completion, any corrosive influences, and the forces associated with running the casing.
An optimum design for a casing string is one designed from "the inside out", a design that is based on supplying a stable casing string of a size to optimize total fluid production over the life of the well (including possibility of secondary or tertiary floods). The effective design of a casing string for any well consists of four principal steps.

1. Determine the length and size of all casing strings that are needed to produce the well to its maximum potential.
2. Calculate the pressure and loads from predicted production and operations such as stimulation, thermal application and secondary recovery.
3. Determine any corrosive atmosphere that the casing string will be subjected to and either select alloys which can resist corrosion or design an alternate corrosion control system.
4. Determine the weight and grade of casing that will satisfactorily resist all of the mechanical, hydraulic, and chemical forces applied.

The sizing of a casing string must be complete before finalizing the bit program during the planning of the well. A casing string can be visualized as a very long telescoping tube with the surface casing or conductor pipe as the first segment and the deepest production string or liner as the smallest, most extended section. Each successive (deeper) segment of the casing string must pass through the last section with enough clearance to avoid sticking. Figure 2.1 illustrates the way the casing string fits together. The drill bits used for each section are usually 1.5 to 3 in. or more larger than the casing 0.d. to be run. When one section is cased and cemented, a bit just small enough to pass through the casing
drift ID is run to drill to the next casing seat (casing shoe set depth). During drilling, departing from the bit program is often required, especially in a wildcat when the fluid pressures in the formations cannot be controlled with a single mud weight without either breaking down some formations by hydraulic fracturing with the mud, or allowing input of fluid from other formations because of low hydrostatic drilling mud pressure (a kick). Ideally, just before this noncontrollable point is reached, the “casing point” is designated and a casing string is run. Economics of drilling and cementing dictate that these casing points be as far apart as formation pressures and hole stability will allow. Use of as few casing strings as possible also permits larger casing to be used across the production zone without
using extremely large diameter surface strings.

Use of small casing severely restricts the opportunities for deepening the well or using larger pumps. Use of small casing to save on drilling costs is usually a poor choice in any area in which high production rates (including water floods) are expected.

Description of Casing Strings

There are several different casing strings that are run during the completion of a well. These strings vary in design, material of construction and purpose. The following paragraphs are brief descriptions of the common required strings and specialty equipment.
 The conductor pipe is the first casing which is run in the well. This casing is usually large diameter and may be set with the ”spudding” arm on the rig (The spudding arm drives in the casing.). The primary purpose of the conductor casing is as a flow line to allow mud to return to the pits and to stabilize the upper part of a hole that may be composed of loose soil. The depth of the conductor pipe is usually in the range of 50-250 ft with the depth set by surface rocks and soil behavior. It also provides a point for the installation of a blow-out preventer (BOP) or other type of diverter system. This allows any shallow
fluid flows to be diverted away from the rig, and is a necessary safety factor in almost all areas. In areas with very soft and unconsolidated sediments, a temporary outer string, called a stove pipe, may be driven into place to hold the sediment near the surface.
The well is drilled out from the conductor pipe to a depth below the shallow fresh water sands. The surface casing string is run through the conductor pipe and has three basic functions: (1) it protects shallow, fresh-water sands from contamination by drilling fluids, (2) prevents mud from being cut with brines or other water that may flow into the wellbore during drilling, and (3) it provides sufficient protection of the zone to avoid fracturing of the upper hole so that the drilling may proceed to the next casing point. This surface casing is cemented in place over the full length of the string and is the second line of safety for sealing the well and handling any high pressure flow. The intermediate string is the next string of casing, and it is usually in place and cemented before the higher mud weights are used. It allows control of the well if subsurface pressure higher than the mud
weight occurs and inflow of fluids is encountered. This inflow of well fluids during drilling or completion of the well is called a kick and may be extremely hazardous if the flowing fluids are flammable or contain hydrogen sulfide (sour gas). The intermediate casing may or may not be cemented in place and, if not cemented, may be removed from the well if an open-hole completion is desired. If a casing string is not hung from the surface, but rather hung from some point down hole, it is called a “liner”. In most wells, the top of the liner is cemented in place to provide sealing. The top of the liner is set inside an upper casing string. The section where the liner runs inside another string is the overlap
section. Production liners are permanent liners that are run through the productive interval. On some occasions] they may be run back to surface in a liner tieback operation. The tieback consists of a downhole mechanical sealing assembly in a hanger into which a linear string or the tie back string is “stabbed” to complete the seal. A cement job seals the liner into place in the casing and prevents leakage from the formation into the casing. The lower part of the casing string, into which the liner is cemented, is called the overlap section. Overlap length is usually only enough to insure a good seal, typically 300 to
500 ft. Overlap length may be longer where water or gas channeling would create a severe problem. Liners are run for a variety of reasons. If the operator wants to test a lower zone of dubious commercial quality, a liner can be set at less expense than a full casing string. Also, in lower pressure areas where multiple strings of pipe up to the surface are not necessary to control corrosion or pressure, the liner can be an expense-saving item. In wells that are to be pumped by ESP’s (Electric Submersible Pumps), the liner through the production section leaves full hole diameter in the casing string above the pay for setting large pumps and equipment. The production casing, or the final casing run into the well, is a string across the producing zone that is hung from the surface and may be completely cemented to the surface. This string must be able to withstand the full wellhead shutin pressure if the tubing or the packer fails. Also, it must contain the full bottomhole pressure and any mud or workover fluid kill weight when the tubing or packer is removed or replaced during workovers. The decision on whether to cement the full string is based on pressure
control, economics, corrosion problems, pollution possibilities and government regulations.

Casing Clearance

The necessary clearance between the outside of the casing and the drilled hole will depend on the hole and mud condition. In cases where mud conditioning is good or the mud is lightweight and the formations are competent, a clearance of 1.5 in. total diameter difference is acceptable. For this clearance to be usable, the casing string should be short. Primary cementing operations may not be successful in this clearance and cementing backpressures will be high. A better clearance for general purpose well completions is 2 to 3 in. For higher mud weights, poorer mud conditioning, poor quality hole and higher formation pressures, clearance should be increased. For more information on hole quality and sticking, review the chapter on Drilling the Pay. Excessive clearances should also be
avoided. If the annular area is too large, the cement cannot effectively displace the drilling mud.
A reference for hole size and casing size for single or multiple string operations are shown in
Figure 2.2.2 The solid lines indicate the common biffcasing combinations with adequate clearance for most operations. The dashed lines indicate less common (tighter) hole sizes or bitkasing combinations. Long runs of casing through close clearance holes usually leads to problems. Tight clearances should be avoided where possible.

Connections

The threaded connection of casing or tubing is important because of strength and sealing considerations. The connections are isolated pressure vessels that contain threads, seals and stop shoulder^.^ The fluid seal produced by a connection may be created in the threads by a pipe dope fluid or by a metal or elastomer seal within the connection. Strength of the connection may range from less than pipe body strength to tensile effciencies of over 11 5% of pipe body ~t rengthT.~hr eads are tapered and designed to fit a matching thread in a particular collar. In the API round thread series, the connection may be either short thread and coupling (ST&C) or long thread and coupling (LT&C) as illustrated in Figure 2.3. If the thread is an eight round, it means eight threads per inch. The length description
refers to the relative length of the coupling and the amount of pipe that is threaded (the pin). Creation of a pressure tight seal with an API round thread requires filling the voids between the threads with a sealing compound (thread dope) during makeup of the joint.

Although the standard 8-round threaded connection is reasonably strong, it does not approach the strength of the body of the pipe. As tensile loads increase toward the limit of the pipe, the connection will normally fail by shearing off the threads from the pipe or by thread jumpout caused by pipe deformation under severe loads.
To make a stronger joint in tubing, a thicker (larger outside diameter) section is left at the end of the pipe so that threads can be cut without making the wall thickness of the pipe thinner than in the body. This form of connection is called external upset or EUE, Figure 2.4. Its inside diameter is the same as the pipe. A nonupset, or NU pipe and several other joint types are shown in Figure 2.5 The outside diameter of the EUE joint is larger than the NU connection, and the coupling or collar is normally manufactured on the pipe. Another method of increasing the strength of the threaded connection is by upsetting the connection to the inside of the pipe. This internal upset restricts the inside diameter of the pipe at every joint and is only used in drill pipe where a constant outside diameter is necessary.
Other sealing surfaces are available in special connections and have found popularity where rapidly made, leak free sealing is important. The two-step thread connection uses two sets of threads with a metal sealing surface between. In other connections, a groove at the base of the box may contain an elastomer seal. A variety of connection types and sealing surfaces are available, Figure 2.5. The disadvantage to the numerous thread and sealing combinations is that the connections cannot be mixed

in a string without crossovers (adaptors). A more detailed discussion of connections are available from other sources.

Chapter I : Drilling the Pay, Selecting the Interval and the Initial Design con't lec ( 5 )

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

Traditionally the main goal of any drilling operation was to keep control of the well. This resulted in a positive pressure from the wellbore outward into the formation stopping the inward flow of all reservoir fluids. Underbalanced drilling with a pressure contained system allows the formation fluids to flow into the wellbore and prevents invasion of the drilling fluids into the formation. Although this method is more difficult to handle with its increasing amount of fluid recovery, it does provide the very best method of damage-free drilling. The elements of an underbalanced drilling system include a contained, safe, surface system that can separate solids, liquids and gases. This type of a separator system generally uses solid separation equipment and a horizontal separator to separate liquids and gases. Other important aspects of underbalanced drilling include adequate hydraulics of the fluid circulation system to allow bit lubrication, cooling and hole cleaning, plus sufficient pressure in the wellbore to prevent full-scale hole unloading. Typically, underbalanced drilling attempts to maintain from 112-2 Ib per gal under the pore pressure. Depending on the permeability of the formation and the type of fluids flowing, the pressure might have to be adjusted to keep the solid separation facilities within their reasonable operating limits.

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 access
laminations 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.

Chapter I : Drilling the Pay, Selecting the Interval and the Initial Design lec ( 4 )

The completion begins when the drill bit first penetrates the pay. Drilling the pay zone is one of the most important parts of the drilling procedure, thus drilling mud that is adequate for drilling the rest of the well may not be acceptable in the pay. Whereas formation damage created by the mud is acceptable in a nonproductive interval, it cannot be tolerated in the pay zone. What is needed is a mud that can control leakoff without creating permanent damage. The mud may require special treatment and occasionally, a changeout of the mud to a nondamaging fluid. There are several goals in drilling besides well control that are of interest to the completions engineer.

1. Drill a usable hole - A hole through the pay that will not accept the design size of casing limits the possibilities of the well and may impair the productivity.
2. Minimize formation permeability damage - High drilling mud overbalance pressure, uncontrolled particle size, mud filtrate that swells clays and poor leakoff control may mask the response of a productive formation to a drill stem test (DST) and may lead to bypassing a producing zone.
3. Control washouts - Hole stability problems may cause hole enlargements that make perforation and formation breakdown much more difficult.
From a drillers viewpoint, there are five main functions of a drilling mud:’ pressure control, bit lubrication, shale stability, fluid loss control and cuttings retrieval. The most important aspects of a drilling mud from a formation damage standpoint are to prevent loss of the drilling mud filtrate and to make sure that the filtrate that is lost will not react with the formation to reduce permeability. Fluid reactivity is usually controlled by using potassium chloride or other salts to stabilize the clay in the formation.2
Potassium chloride may not always control clay reactions or may require as much as 4% or more salt where smectite clay is present in the larger pore passages. Fluid loss control is accomplished by rapidly sealing off the permeable sections of the formation^.^^^ The mud accomplishes this fluid loss control by creating an almost impermeable mud cake of particles on the surface of the formation where leakoff occurs. The mud cake is produced by simple dehydration; as the liquid penetrates into the formation (the mud filtrite), the solid particles are stranded on the surface of the formation. In a properly formulated mud, there are a wide range of particle sizes that, on dehydration, fit together into a tightly compacted, very low permeability seal. By carefully controlling the size range of particles and minimizing
the clay size particles that could invade the pores of the formation, invasion damage from particles can be stopped. 4-7 In some drilling and workover fluids, fine particles and at least parts of the solids in the fluids will be designed to be acid soluble.8
The time required to form the mud cake will depend upon the mud characteristics, the permeability and the pressure differential, (Must be toward the formation for well control!) A higher permeability formation will generate a mud cake very rapidly than a low permeability formation since the rate of initial fluid loss (spurt) is higher. After the mud cake is formed, further liquid losses depend on the permeability of the cake. Formation of a cake does not insure that leakoff stops. In cases where the formation matrix permeability is between approximately 0.5 md and 100 md and the pressure differential toward the formation is small (APc1 00 psi), the filtrate of even a damaging mud will not likely extend into the formation beyond a depth of a few inches provided that the filter cake is successful in controlling leakoff. To build a successful mud cake, there must be leakoff. If the permeability is very low (e.g., kc0.05 md), the filter cake may be only poorly formed and fluid loss could be much higher than expected. This is especially true when the pay is an upper formation in a
deep well where a high density mud is used and the formation is exposed to the mud for a long period of time. Fortunately, most very low permeability formations require fracture stimulation, so the zone of damage is easily bypassed. The occurrence of the damage is important, however, since a productive interval might be missed on a test of an unstimulated well. The higher permeability formations pose special problems if the mud cake cannot be formed quickly. Since every trip out of the hole scrapes off much of the protective mud cake, the cake must reform easily to prevent the loss of large volumes of
mud filtrate into the formation. Tell-tail identifiers of a permeable formation are deflections on the SP log, bit drag and where the caliper log shows a narrow spot of slightly less than the bit diameter. This sticking point should not be confused with borehole deformation; a plastic flow of the rock in response to bore hole deformation, active faulting, folding, salt domes, etc.l5 The depth of damage created by the filtrate of the mud is directly related to the amount of driving pressure that the mud exerts on the formation. Even with a high quality mud, damage can be very deep if there is high mud overpressure. When high pressure zones elsewhere in the hole require the use of high pressure on the mud system, lower pressure zones are forced to take fluid by the pressure differential. This situation becomes critical when a zone that may be pay is broken down and fractured with the mud. Several hundred barrels of mud can be lost when the well is fractured. Some wells damaged
in this way never produce as expected. The only safe way to prevent this type of fluid loss from occurring is to case through the zones requiring high mud weights before the pay zones are drilled. Improving the filter cake and making the mud filtrate more compatible with the formation is one of the best methods of controlling formation damage. The use of inhibited filtrate prepared with potassium chloride (such as 2% KCI) will often minimize the formation damage in pays with even water sensitive sandstones.
In formations that are sensitive to fluid, the total time that the sensitive zone is exposed to mud may be critical. Once a section of the well that is known to be sensitive is penetrated, operations should continue as quickly as possible until casing can be cemented over the zone. This treatment is usually  reserved for sections of caving shale or other unstable formation; however, it may also be used very successfully in drilling pay zones that are water sensitive. If loss of permeability is plotted against accumulative fluid loss from the mud, permeability damage increases very steadily as total fluid loss increases, almost regardless of the type of fluid. This emphasizes the importance of maintaining a
high quality mud and lowering the exposure of the formation to fluid loss.
Most of the solids and cuttings from the mud are halted at the formation face and very little penetration occurs unless a poorly designed mud with a large amount of clay or silt sizes particles are used in a formation with large pore throats. The damage from these solids is most apparent in the form of formation face plugging. Movement of the solids into the formation is dependent on the size of the pores, particle size and quantity of the finest solids in the mud. Although some tests have shown several centimeter penetration of fine mud particles into high permeability ~andstonea,~ p roperly conditioned mud will probably not invade the formation.
If the formation has rubble zones (very poorly sorted grains with sizes that may range from fines to small boulders), very permeable porous sections, fractures or vugs, then severe whole mud penetration may occur and produce lasting formation damage. It is very advantageous to design the mud or completion fluid to bridge off on the face of the formation to prevent the possibility of particle invasion.
When the mud or kill fluid cannot be circulated, the formation has a lost circulation zone that has very high permeability or cannot support the weight of the mud column without fracturing. For these problem cases, special pills of LCM, lost circulation material, are often run to plug off the high perm zonesg Where the formation will not support the mud column, a cement sheath is often tried to reinforce the zone. After setting a cement plug, the hole is redrilled. The cement invades fractures and vugs, adding strength and controlling leakoff. One problem with lost circulation material (LCMs) cases is that drillers use a variety of LCMs, such as paper, sawdust, leather, grain, etc., that are very effective in preventing leakoff but cannot be removed if the zone is a pay zone. Any LCM used in a potential
pay must be easily removable. The decision on whether a mud system should be changed before the pay is drilled depends upon the sensitivity of the pay to the mud filtrate. If the formation contains swellable clays such as smectite, a filtrite sensitivity test on core from an offset well will tell whether the formation is damaged by introduction of the mud filtrate. Where core is not available, a mud with a low damage potential (potassium chloride) should be considered. Smectite clay in the pore throats is usually reactive to fresh fluids, up
to 5% or more KCI is sometimes needed to prevent clay problems in formations that have 3 to 8% smectite. In gas zones, the use of most oil-based muds should be avoided unless the mud has been proven to be of a nondamaging nature in the zone of interest. In oil or gas zones that are to be frac-tured, less emphasis is placed on the mud damage at the wellbore since a fracture will extend beyond the damage.
When natural fractures or vugs are present in the pay, whole mud can be lost. In these situations, it is often necessary to set a casing string above the pay and drill the formation without returns or use a fluid loss control additive capable of sealing fractures at the wellbore. Other methods, such as drilling the well while flowing and diverting the produced fluids, have also been considered but are dangerous in high pressure formations.
Because of damage by both incompatible filtrate and the migration of very small particles in the mud, the completion zone in many wells has been drilled with completion fluid. This practice eliminates much of the damage from mud and mud filtrate. The basic problem with the process is in completely cleaning the hole and pipe of residuals from the mud so that the left-over mud and cuttings do not contaminate the completion fluid. Fluid loss from solids free systems may be very high, especially in high permeability formations.
In very sensitive pay zones, the wells are often drilled with mud to the top of the pay and the pay itself is drilled with air, mist or foam to reduce the amount of water in contact with pay. Another method of reducing formation damage is to drill the pay with reverse circulation. This approach has been used in sensitive formations to limit the contamination of the mud by drill cuttings. Regardless of the formation sensitivity, well control must always be the Number 1 priority. The importance of drilling a usable hole through the pay and its importance on running and cementing pipe cannot be overstated. Failure to get a casing string or a liner to bottom can be very costly in terms of cost of an additional string or liner and the reduction of working space where pumps and other equipment need to be set. Simply drilling a hole with a certain diameter drill bit through a formation does not lead to a hole that will accept a string of pipe of an outside diameter just smaller than the
drill In most instances where casing cannot be run in a freshly-drilled hole, the problem is that a usable hole has not been drilled, i.e., the drift diameter of the hole is not equal to the bit diameter.
This problem is shown schematically in Figures 1.1 and 1.2. Figure 1.1 illustrates problems with hard ledges or changes in formation, while Figure 1.2 shows an extreme case of bit wobble. The spiral hole illustrated in Figure 1.2 was caused by an under-stabilized bit creating a hole too small to run the planned casing. Normally, casing strings are run with 1-112 to 2 in. minimum clearance between the hole diameter and the outside diameter of the pipe. In a straight hole, this is adequate clearance, but in a hole with an incorrect BHA (bottomhole assembly of drilling bit, collars, and stabilizers), problems will develop during running of the pipe. Drilling “slick” (drill collars in the BHA without stabilizers) usually
leads to a hole with a usable diameter significantly less than the diameter of the drill bit. Estimation
of this usable hole or drift diameter is:

The formula points out that the usable diameter of the hole may be smaller than the bit. If the hole has been drilled with the intention of running a liner, the problem may be even more pronounced. Liners are usually characterized by close tolerances between the pipe and the hole, thus it is essential that good hole diameter stability be maintained.
The type of drilling mud may also make a difference in getting pipe to the bottom. Differential sticking is caused by a pressure differential into a permeable zone that holds the pipe (or logging tool) against the wall and buries the lower side of the pipe in the mud cake.14 Sticking is increased by thick mud cakes because of increased contact area, Figure 1.3. An efficient mud forms a thin, slick mud cake with very low permeability. A thin mudcake keeps the pipe from becoming deeply embedded, resulting in less torque and drag.14 The goal is a high colloidal clay-to-silt (or cuttings) ratio that produces a slick, thin cake.

Diagnostics of stuck casing are often made after examining the drilling record and trying different types of pipe movement and circulation. A simple, stuck pipe diagnostic routine is shown schematically in Figure 1.4.14

Calculating the true vertical depth, TVD, from the measured vertical depth, MD, can be accomplished for consistent deviated wells from simple trigonometry or from tables. When wells use long turn radii, other corrections may be needed.
During drilling of wildcats or field development wells in sparsely drilled areas, mud density is handled as a function of well control, with pore pressures estimated from other data. In this type of environment, high mud overbalance conditions may occur, especially in deep formations. Although fracturing is the most obvious effect of high mud weights, excess formation permeability damage may also occur. In a study of factors influencing stimulation rates, Paccaloni, et al.,16 reports that in formations greater than 100 md, 90% of DST's were dry or doubtful when an overbalance of over 11 00 psi was used during drilling. Excessive mud overbalances should be avoided in pay zones.

Well Planning lec ( 3 )

Well Planning

Before initial operations are started on any well, a plan should be constructed that will take the well from initial drilling to plug and abandonment. There are a series of steps and operations that go into completing a successful well. Many of these are interconnected, and the expense of a well in today’s market requires that consideration be given to efficient economical planning. The method of planning is the same, regardless of the use of the well. Planning starts with cooperation and information exchange between explorers, drillers, completions and operations engineers and foremen, partner companies, service companies, equipment providers, and government regulatory officials. The information gathered in this step often prevents expensive misunderstandings that would occur during the drilling or completion of the well or disastrous environmental problems that could result from improperly executed operations. Each of the functional operations in well service involves
specialists. Too often these specialists do not have a good knowledge of the operation of other parts of the industry, and the effects that their specific actions will have on the other operations of a well. One of the first basic needs in today’s environment is to prevent pollution. There is a need to isolate all usable waters from contamination during the drilling, completion, or producing process. This step requires careful design and a concerted effort on the application side. The requirements include casing that will withstand pressure and the corrosive atmospheres that will be experienced during the life of a well, even if a sweet well turns slightly sour. It also requires consideration of cement placement and elimination of any possible means of migration of fluids through or around the borehole.
The expected use of a well, whether it be observation, production, injection, or a multiple purpose well, will influence where the well is placed, how large the casing is, and what corrosive service ratings will be required. It should be remembered that many wells serve more than one purpose during their lives.
The reservoir conditions will obviously affect the completions. The factors that are most known in this area are temperature and pressure. However, fluids, viscosity, corrosiveness of the fluids, and even the rate of fluid production become very important. Factors which are not always considered include the tendency for formation of scales, emulsions, paraffins, and asphaltenes. It is very possible by modification of the tubing string or the incorporation of special coatings to almost completely prevent many scale problems.
The rate of fluid production is the main factor in selection of the casing size. Expectations of a very high rate well cannot be met with small casing. Problems such as this are often in direct contrast to efforts to reduce well costs by using a small casing string or a small tubing string. Although initial savings in these areas can easily be made, the long-term benefits of the well weigh in heavily for larger tubulars. There are also alternatives to conventional tubing and casing strings such as monobore completions, velocity strings, tailpipe extensions, and the use of coiled tubing for rapidly run and retrieved tubing strings.
The amount of service needed during the life of a well certainly has an influence on the topside connections and the location of the wellhead itself. For sweet gas wells with very low liquid production, remote wellheads or subsea wellheads in offshore fields make very good sense. These wells would only be good where well intervention was at a minimum.
Perhaps one of the most difficult parts to effectively plan are multiple layered reservoirs. In this problem area, there is a need to process all of the reservoirs without permitting crossflow from one zone to another. Obviously, individual wells could be used to isolate each zone. However, the expense of drilling and completion are usually too high to make this a viable alternative, except in the highest rate producing areas. Other methods of effectively producing multiple reservoirs or layered reservoirs include a variety of techniques, such as tubing selectives, multiple completions, and sequenced production of reservoirs. Commingling of zones should be done when permitted by pressures and reactants that may form by mixing waters or oils of various zones. Physical well design parameters should have been dictated by the expected producing behavior of the well. Sizes of tubing and casing are set before the drilling bit selection process. During the tubular
design, the use of pup joints (short joints of casing to improve depth control of perforating and other operations), nipple locations, and the use of special equipment in a string, such as subsurface safety valves that require larger casing, are needed early in the design phase of the well. In most cases, it is advisable to minimize the number of restrictions in a producing string to make sure needed tools can pass through the string and to prevent deposits that are often caused downstream of a flow restriction. Cementing operations should be carefully planned and applied to eliminate channeling of fluid. Too
often it is assumed that the primary cement job will be a failure before the job is even pumped. This type of thinking leads to a haphazard placement of cement and a self-fulfilling prophecy requiring expensive squeeze cementing. It has been shown in a number of tests that proper quality control and attention to detail can result in effective primary cementing jobs. Perforating planning is an area that could definitely use attention during both planning and application. A variety of processes and tools are available from underbalanced to extreme overbalanced perforating and from wireline perforating to tubing conveyed perforating. Perforating expense can run from a few thousand dollars to over one hundred thousand dollars, depending on the needs of the well and the care with which it is designed. Expensive techniques are by no means always needed. The type of artificial lift that will be used on the well should have been decided long before the well was drilled. A number of artificial lift methods are available: gas lift, beam lift, plunger, jet lift, progressive
cavity pumps, electric submersible, and natural flow. Of these lift methods, beam lift, gas lift, and electric submersible pumps probably make up at least 98% of the artificial lift cases. Many wells that are on natural flow early in their life have to be artificially lifted as pressures decline or as fluid volumes increase to the point where gas drive and natural gas lift are no longer sufficient. The ability to change lift methods as fluid volumes increase or decrease is required for well operation optimization. If the casing and packer are designed with a conversion in mind, the switch of lift systems is easy.
Some formations have special needs, such as sand control. When the strength of the formation is not adequate to prevent sand grains from being dislodged by the drag forces encountered in production, then special completion techniques are needed to prevent the sand from entering the wellbore. A number of techniques have been tried, with resin consolidation of the sand and gravel packing being the primary control mechanisms. The real concern in most sand control jobs is not what type of control, but whether sand control is needed and when it is needed. The factors that cause sand movement change during the lift of the well. Some wells that will not experience sand production until after water breakthrough are gravel packed from initial completion. This is a large initial expense that can, in some cases, be delayed. Produced fluids including oil, gas, water and returning injected fluids are all reactable fluids. In addition, the well is a reactor when these fluids are moved through the well path. Conditions within this “reactor” include temperature, pressure, pressure drop and other factors such as metallurgy and clearances within the structure of the well. When the well flow path from formation to tank battery is correctly designed for the flow of a particular fluid, the detrimental reactions are very few. But when the well design is not suited to the particular fluids that must be produced, a “problem well” is often created. Produced fluids are a reactant-rich %oup” composed of natural surfactants in both the oil and the water, free and dissolved salts, hydrocarbons with carbon chain links from C, to Cso, dissolved and free mineral and hydrocarbon gases, bacteria, micelles, and over 20 possible combinations of emulsions, foams, froths, and dispersions controlled and stabilized by such things as pH, viscosity, internal phase concentration, and surface energy. When an upset occurs, the panic that ensues usually requires a quick fix. When the tank battery goes down because of a tank of “bad” oil (oil with a higher than allowable water content), chemical treating is usually required as an emergency procedure to reduce the water content and return the well to production. The total chemical approach may
be short-sighted in some instances, particularly when production upset symptoms are treated in a cyclic manner. The best approach often requires an understanding of the individual reactants and their relationship to both each other and their flow path environment. Often problem wells will yield improvements only when physical changes are made in the well design. Numerous instances are available that show chronic production upset problems being eliminated when physical changes were made to the well architecture.
An understanding of production chemistry is a critical factor in designing the downhole and surface equipment that makes up the well’s system. The approaches that must be used are much the same as initial design; however, the knowledge that liquid and gas volumes, relative amounts and pressure will change over the life of a project. Thus, some flexibility must be built in to achieve a low maintenance well system.

In general, several steps are followed when evaluating and/or designing a well system.
1. Most emulsions, including emulsions, sludges, froths, foams and dispersions, are most troublesome because of energy input and a stabilizing mechanism. By eliminating one or both of these two factors, a significant decrease can be attained in problems with phase separation. The lift system and pressure drops within the flowing system are the chief inputs of energy into an emulsion.

 2. Upsets following acidizing or any type of chemical treating may be severe and are generally based either on a solid material added with the chemical injection or by a variance in pH which affects the behavior of natural surfactants. Tracking and controlling pH can often be a significant factor in eliminating problems with upsets.

3. Production of solids from a well creates problems with emulsion stabilization, solids abrasion and all types of fluid separation. Where possible, flow of solids should be identified and the source minimized. The lift system must be designed for the expected rate after a stimulation and must take into account the recovery of the stimulation load fluid plus the method with which it commonly flows back. The most severe problems in these areas generally include hydraulic fracturing and acidizing. Once an acid job has begun
to flow back, the pH may drop, significantly affecting the amount of corrosion during the load fluid recovery stage. Jobs involving proppant fracturing often give problems because of proppant flowback in the produced fluids during the initial stage of fluid flow.
In old wells and in marginal wells there is probably no stronger need than that of consideration of produced water control. Water comes in as a response to low pressure caused by hydrocarbon production.
There may be many scenarios of water production. In some cases water drives the hydrocarbons toward the wellbore. If you shutoff the water, you will reduce the hydrocarbon production volume. In other cases leaks through bad cement, corroded casing, or through fractures can flood the well with extraneous water. In these cases a water control treatment is often useful. Where bottom water drive is severe, horizontal wells have often been used to successfully produce hydrocarbon without severe water production problems. Each of these possibilities can be addressed in the initial well plan. Control of corrosion is needed throughout the life of the wells. In many applications the well will have a very low corrosivity when first drilled, but the corrosion rate will go up significantly during the life of a well. In many wells, the original casing lasts 20 or more years before leaks are detected. Repair may bring temporary relief, but leaks may often return within a few months. Special inhibitor programs are needed as well conditions change.
Formation damage has been mentioned in earlier paragraphs, and it is well to remember that formation damage may recur during the life of the well. The most prevalent times for formation damage occurrence are during workovers and when pressure declines or water from a floodfront causes precipitation of either organic or inorganic components in the formation or in the tubing string. Modeling can often show a trend of formation damage and its effects, but the actual occurrence of formation damage can probably not be adequately predicted by any model without very exacting knowledge of well behavior.
The occurrence of formation damage or drilling of a formation that is lower permeability than expected may require stimulations. Stimulations, including fracturing, acidizing, heat, and solvents, can be applied on almost any well provided that the support equipment and the tubulars will allow the techniques to be implemented. If formation damage or stimulation need can be adequately forecasted early in the life of the well then cost reduction is often possible. For projects where enhanced recovery is envisioned, well placement and spacing become critical. In these applications the use of horizontal wells, deviated wells, and vertical wells are necessary to adequately process and sweep the reservoir. It is unfortunate that we know enough about reservoir to adequately place wells only when the reservoir is nearing depletion. With new techniques however, such as well-to-well seismic and 3D seismic, improved mapping of the reservoir if possible. This type of investigation may also yield additional pay zones and how those pay zones can be accessed. Every well that is ever drilled will require plug and abandonment. The techniques for plugging abandonment
and the rules are many and varied. The underlying objective however is very plain. Wells
should be plugged in a manner in which the fluids that are in the reservoirs will stay isolated. This need for isolation should be an overriding concern in any completion planning and must be accounted for when processes such as fracturing or well placement are considered.

Introductions Geology lec ( 2 )

The geologic understanding of the pay and the surrounding formations plays an important part in the design of well completions and stimulations. The brief introduction given here will only give a glimpse of the subject matter in the field. This treatment of geology is very simplistic; reference articles and books are available for every segment.
The type of formation, composition, strength, logging basics, leakoff sites and other parameters may be available from a detailed geologic investigation. This information is useful for pay zone identification, fluid and additive selection, longevity of fluid contact, and selecting casing points.
There are several major classifications of rocks of interest to the petroleum industry: sandstones, carbonates (limestone and dolomite) evaporites, and shales are only the major groups. Several others, such as mudstones, siltstones and washes, are subdivisions of the major classifications.
Sandstones are predominately silicon dioxide and may have various amounts of clay, pyrite, calcite, dolomite or other materials in concentrations from less than 1 % to over 50%. Sandstone formations are generally noted for being a collection of grains. The grain size may range from very small, silt sized particles (5 microns) to pea size or larger. The grains fit together to form a matrix that has (hopefully) some void space between the particles in which oil or other fluids may accumulate. The grains are usually held together by a cement that may be clay, silica, calcite, dolomite, or pyrite. Some cementation of the grains is critical for formation strength; however, excess cementation reduces porosity and permeability.
Sands are deposited in a variety of depositional environments that determine the initial sedimentkock properties. The depositional environment is simply what type of surroundings and forces shaped the deposits. In the following descriptions of depositional environment, the energy level is labeled as either high or low depending upon the level of force that accompanied the deposition of the sediments. High energy deposits are those with sufficient wind or current to move large pieces of debris while low energy is sufficient to move only the smaller particles. The importance of energy is described later.
Common depositional environments are:

1. Deltas - These mouth of river deposits provide some of the larger sandstone deposits. Because of the enormous amount of natural organic material swept down the river systems, the deltas are also rich in hydrocarbons. Quality of the reservoir rock deposits may vary widely because of the wide variations in the energy level of the systems.
2. Lagoonal deposits - May be regionally extensive along the shores of ancient seas. Lagoonal deposits are low energy deposits that are hydrocarbon rich. Permeability may vary with the energy and amount of silt.
3. Stream beds - A moderate to low energy deposit with some streaks of high energy along the fast flowing parts of the streams. Stream beds are known to wander extensively and chasing these deposits with wells requires very good geologic interpretation, plus a lot of luck. The deposit volumes are also limited and frequently deplete quickly.
4. Deep marine chalks - These are often the most massive deposits available, built up at the bottom of ancient seas by the death of millions of generations of plankton-sized, calcium fixing organisms. They can be very consistent, thick deposits. Natural fracturing is common.
5. Reefs - These formations were built in the same manner as the reefs of today, by animals that take calcium from the sea water and secrete hard structures. Because of the cavities remaining from the once living organisms, reefs that have not undergone extensive chemical modification are among the most permeable of the carbonate deposits

6. Dunes - The effects of desert winds on the sands have a shaping effect that can be seen in the arrangement of the grains. These deposits may be massive but are usually lower energy. Permeability may vary considerably from top to bottom.
7. Alluvial fan - Zones of heavy water run-off such as from mountains are extremely high energy runoffs. Common constituents of these formations may range from pebbles to boulders and cementation may be very weak. Formations such as the granite washes are in this classification.
8. Flood plains - Occur along lower energy rivers and form during flood stages when the rivers overflow the banks and spill into adjacent low areas. Flood plain deposits are mostly silt and mud.

The level of energy with each type of deposit can be visualized by their modern depositional counterparts.
The importance of energy is in the sorting of the grains and the average size of the grains. As seen in the description of permeability in the preceding section, a rock with larger grains and the absence of very small grains leads to high permeability. When small grains are present, the permeability is much lower. When there is a mixture of the very large and very small grains, such as in some alluvial fans, the permeability can be very low. The extent of grain differences in a formation is termed the “sorting”, with well sorted formations having similar sized grains and poorly sorted formations showing a very wide size range.
The events that happen after the deposit is laid down are also factors in well completions and may have a devastating effect on reservoir engineering. Some of these forces are active for a short period in geologic time such as faulting and salt domes, and others like salt flows and subsidence, are active during the productive life of the well. The faulting, folding and salt movement make some reservoirs difficult to follow. Continuous forces are often responsible for formation creep in open holes, spalling, and casing sticking and collapse problems. Although these geologic movement factors cannot be easily controlled, the well completion operations can be modified to account for many of them, if the problems
are correctly identified early in the project life.
Chemical modifications also influence the reservoirs, though much less drastically than the uplift forces of a salt dome, for example. Most carbonates (not including the reefs) are laid down by accumulation of calcium carbonate particles. Limestone may recrystallize or convert to dolomite by the addition of magnesium. Because the limestone is soluble in ground water and very stable (resistant to collapse), the limestones are often accompanied by locally extensive vugs or caverns which form from ground water flow. Recrystallization or modification by the water as is flows through the rock may also lead to a decrease in porosity in some cases.
When dolomite forms, a chemical process involving the substitution of magnesium for part of a calcium in the carbonate structure generally shrinks the formation very slightly, resulting in lower microporosity but slightly higher porosity through the vugs or the natural fracture systems. Other types of dolomitization are possible. The carbonates are marked by a tendency towards natural fractures, especially dolomite. The chalk formations may be almost pure calcium carbonate, are reasonably soft (low compressive strength) and may have very high porosities on the order of 35-45%, but relatively low permeabilities of less than, typically, 5 md.
The third formation of interest is shale. These formations are laid down from very small particles (poor sorting) that are mixed with organic materials. The organic material is often in layers, pools, or ebbs.
The shales may accumulate in deep marine environments or in lagoonal areas of very low energy resulting in almost no large particles being moved. The shales are marked by high initial porosity and extremely low permeability. Shales often serve as a seal for permeable formations. The shales are also extremely important, since they are the source for the oil that has been generated in many major plays. Oil leaves the shale over geologic time and migrates into the traps formed in sandstones, limestones and other permeable rocks.
The evaporites are deposits that are formed by the evaporation of water. Deposits such as anhydrite are usually accumulations of dried inland seas and serve as extensive local geologic markers and sealing formations. They are extremely dense with almost no porosity or permeability.
When a deposit of oil and gas is found, it usually has its origins elsewhere and been trapped in a permeable rock by some sort of a permeability limiting trap. The trapping mechanism is too extensive to be covered in a short explanation on geology, but the major traps are outlined in the following paragraphs.

1. Trapping by a sealing formation is common and accounts for some major fields. These occurrences, called unconformity traps, are where erosion has produced a rough topography with peaks and valleys. Like the rolling terrain of the surface, most formations are rarely flat; they have high and low points and may have a general rise in a direction. If an extensive sealing formation is laid down in top of the sandstone (or other pay), and the sand is exposed to migrating oil from a lower source over geologic time, the oil will accumulate in the higher points of the pay and trend “uphill” toward the point where the hill drops off or another sealing event stops the migration. Tracking these deposits is best accomplished with as complete a structural map as can be constructed. These maps of the formations highs and lows compiled from seismic and drilling data indicate the better places to drill a well -- small wonder that the maps are among the most closely guarded secrets of an oil company.

2. Faulting is an event that shifts a large block of the formation to a higher or lower position. The misalignment of the zones often provides contact with sealing formations and traps the hydrocarbon. There are several types of faulting depending on the action and movement of the rock. In areas of extensive tectonic plate movements, faulting may be extensive.

3. Folding is an uplift or a drop of part of the formation where the breaks associated with faults do not occur. The formation maintains contact with itself, although it may form waves or even be turned completely over by the event. Complete turnover is seen in the geologic overthrust belts and accounts for the same formation being drilled through three times in one well, with the middle contact upside down. Vertical wells directly on the fold will  penetrate the formation horizontal to the original plane of bedding. Although these wells offer increased local reservoir quantity when they are productive, the problems with directional permeability and sweep in a flood are often substantial.

4. Salt domes cause uplift of the formation and result in numerous small or large fields around their periphery. Faulting is often very wide spread. Brines in these areas are frequently saturated or oversaturated and evaporated salt formations, stringers and salt-fill in vugs are common. Because of the uplift of some formations from deeper burial, the productive formations may be over pressured.

5. Stratigraphic traps (permeability pinchouts) are a change in the permeability of a continuous formation that stops the movement of oil. These deposits are very difficult to observe with conventional seismic methods. This effect, combined with a sealing surface to prevent upward movement of fluid forms numerous small reservoirs and a few massive ones. Permeability pinchout may also explain poor well performance near the seal. Laminated beds with permeable sands sandwiched between thin shales are a version of the pinchout or stratigraphic trap. These deposits may be locally prolific but limited in reservoir and discontinuous. Linking the sands is the key to production.
The age of a formation is dated with the aid of fossils which are laid down with the matrix. The age of a formation is important to know if the formation has a possibility of containing significant amounts o hydrocarbon. In most cases, very old formations such as the pre-Cambrian and Cambrian contain very little possibility for hydrocarbons unless an uplift of the structure has made the formation higher than an oil-generating shale, and oil has migrated into a trap inside the formation.

Formation Sequences and Layering

Formations are almost never homogeneous from top to bottom. There is a considerable amount of variation, even in a single formation, between permeability and porosity when viewed from the top of the zone to the bottom. When formations are interbedded with shale streaks, they are referred to as a layered formation. The shale streaks, often laid down by cyclic low energy environments, may act as seals and barriers and form hundreds or thousands of small isolated reservoirs within a pay section  Many times, the layering is too thin to be spotted by resistivity or gamma ray logs. When a formation is known to be layered, the completion requirements change. Perforating requirements may rise from
four shots per foot to 16 shots per foot, and in many cases, small fracturing treatments may prove very beneficial even in higher permeability formations.

Introduction: Basic Well Completion Concepts lec ( 1 )

Porosity

Porosity is the fraction of the total volume of the rock that is pore (non rock) space or void and not made of solid pieces of the formation. It will be filled with a gas, water or hydrocarbon or two or more at the same time. Porosity will range from a high of 40-50% in some marginally consolidated chalk formations to a low of near zero in some of the evaporites (anhydrite). The average porosity of producing reservoirs ranges from about 515% in limestones or dolomites, 10-25% in sandstones and over 30% in many of the chalk formations. In most unconsolidated formation, porosity depends upon the grain size distribution; not on the absolute size of the grain itself. Porosity can be in the order of 35-40% if all grains are close to the same size, but in most cases where a wide range of grain sizes are available, the porosity will be between 15-25%. Severe cases of formations with mixtures of large and very small grains may have porosities less than 15%.
Lower porosities, such as 10% or less, are usually the result of chemical modification of the pore structure, i.e., recementation, precipitation of additional minerals, or leaching and reprecipitation. In some cases, the very consolidated sandstones with overgrowth of quartz may have porosities down to near zero. Geologists further subdivide porosity into several descriptive classifications that help engineers describe the flow of fluids through the formation and into the wellbore. The major classifications are briefly described in the following paragraphs.

1.  Matrix porosity or intergranular porosity - the porosity between the grains of the formation.
2.  Vug porosity - porosity in the solution chambers that may range from a tenth of a    millimeter to voids larger than a basketball.
3.  Fracture porosity - the void space created within the walls of an open natural fracture.
4.  Micro porosity - the voids between the clay platelets or particles. Although a large micro porosity

may exist, production of fluids from them is often difficult since the fluids are usually held by
strong cohesive forces.
The matrix porosity is referred to as the primary porosity and most other porosities are secondary. Usually, the pore space described by natural fractures and vugs are produced or swept very early (flush production) and their continuing use becomes as a conductive pathway to the wellbore. Long term production rate estimates are usually based upon the reserves in the matrix except in very large fields where solution porosity (vugs) is very extensive. Porosity values derived from neutron or sonic logs are usually used alone with other log information and well observations to establish whether a section of rock is “pay.” Although the use of porosity in this manner is common, it can also be very misleading. Obviously, porosity is not a “stand along” value for establishing the quality of ‘pay.” Shales, for example, have porosities of 30% or more but lack the conductive pathways (permeability) to make them economic except where fractured gas-rich shales

exist in massive sections. The location and type of porosity has a great affect on the performance of a well. Relying totally on a log derived porosity, especially in a carbonate, may provide unexpected low production or may result in missing productive intervals. The occurrence of lime muds, a low porosity deposit common within limestones may isolate porosity and result in much lower effective porosities than reported with a log. Fossils, 

Saturation

The fraction of pore space containing water is called the water saturation and usually denoted by an Sw. The remaining fraction of the pore space that contains oil or gas is called hydrocarbon saturation Sh. The simple balance sh = 1 - Sw accounts for all of the pore space within a rock. In almost every porous formation, there is at least a small amount of water saturation. Usually when the sediments were laid down, the matrix materials were dispersed in water. As the hydrocarbon entered the porous formation, water was displaced from many of the pores, although the displacement process is not efficient enough to move all the water. This displacement process, whether it was oil displacing
water over geologic time, or water displacing oil during water drive or water flooding, results in a lower saturation of the fluid being displaced. If a very large amount of the driving fluid is displaced, the quantity of the initial fluid reaches a point, usually a few percent of the pore space, where it cannot be reduced further. This level of fluid is the irreducible saturation of that fluid. Therefore, an irreducible water saturation, S,,,i, is the saturation of water in the core that cannot be removed by migration of hydrocarbon. This water or oil, Soil may be trapped in the small pores, held by high capillary attraction, or bound to clays as a surface layer or in the clay lattice.

Permeability

Permeability, denoted by a lower case k, is a measure of the conductance of the formation to flow of a fluid. The higher the permeability, the easier it is (takes less driving pressure) for a fluid to flow through the rock matrix. The “law” was originally derived by a French engineer named d’Arcy to account for the flow of water through sand filters. The original permeability concept used darcies as a unit of measurement, but most productive formations will be between 0.001 md (1 md = 0.001 darcy) and 1000 millidarcies (1 darcy). Permeability depends on the absolute grain size of the rock, how well the sediments are sorted, presence of fractures, and how much chemical modification has occurred in the matrix. Flowing and bound fluid properties also affect the permeability. Large-grained sediments with a minimum of fine particles (large, open pores) usually have high permeabilities whereas very
fine-grained sediments with small pores have lower permeabilities. Porosity does not always relate directly to permeability. Materials such as shales and some chalks may have very high porosities but low permeability because of lack of effective connection of the pores.
Permeability to oil, water and gas may be different because of viscosity differences and other influences such as wetting and the issue of the thickness of the liquid coating on the pore wall. Oil wet formations are usually thought to be less permeable to the flow of water than water wet formations because the molecular thickness of the oil coating is thicker than that of water. This leaves less pore space for fluids flow. When more than one phase exists in the pore, relative permeability relationships govern the flow.

Relative Permeability

The effects of relative permeability explain many of the problems involved in formation damage and reduction of flow from a formation, either on initial production or after treating with a material which severely oil wets the formation. As will be pointed out in the chapter on formation damage, problems with relative permeability include a significant drop in permeability to the saturating fluid as trace amounts of a second, immiscible phase are introduced in the flowing liquid. Reductions of up to 80% of initial permeability are common when saturation of an immiscible phase is increased from zero to approximately 20 or 25%. It is this significant reduction in permeability that explains much of the damage behind overtreatment with an oil-filming chemical, such as an oil-based drilling mud, or the use of highly absorptive surfactants or solvents. The surface of the rock also plays an important part since the charge of a surfactant controls the attraction to a particular formation face. It must be remembered that severe wettability problems such as the absorption of cationic materials onto sandstones and the absorption of anionic materials onto limestones can play a significant role in permeability reduction. The reduction from this coating or wetting may be severe and can be long-lasting, depending on the tenacity of the coating. Matrix cleanup of this type of wetting is imperative to fully restore the flow capacity of the formation.
Cleanup of this type of damage must take into account both the stripping of the relative permeability influencing layer and the type of rock surface to which it is adsorbed.

Natural Fractures

Natural fractures are breaks in the fabric of the rock caused by a wide variety of earth forces. These natural fractures may have widths of a few thousandths of an inch to a tenth of an inch or more. Natural fractures generally have a common direction that corresponds to forces generated by a significant geologic event in the area such as folding, faulting, or tectonic forces. Where solution etching or cementation forces are active, the fractures may be widened into extensive vugs with permeabilities of hundreds of darcies or filled completely with precipitated minerals. Stylolites or gouge filled fractures are examples of these behaviors. Natural fractures influence flush production or high initial production rate that diminishes quickly after bringing on a new well or the start of flow in a well that has been shut-in. Although they serve as conductive pathways for oil or gas production, they also will transmit water at a much faster rate than the formation matrix, leading to early breakthrough of water or other type floods and sweep problems in reservoir engineering.

Reservoir Pressure

The pressure that the reservoir fluids exert on the well at the pay zone is the reservoir pressure. In single pay completions with little or no rat hole (extra hole below the pay), the reservoir pressure is the bottom hole pressure, BHP. The initial reservoir pressure is the pressure at the time of discovery. Flowing bottom hole pressure is pressure exerted as the result of a drawdown (differential pressure produced by flowing the well). Shut-in pressure is the stable pressure reached after the well has been shut in long enough to come to equilibrium. Shut-in pressures are often quoted as a function of time. The initial pressure is usually a function of depth of burial but may be modified by other forces at the
time of burial or at a later time. Driving pressure may be supplied by a number of mechanisms depending upon the characteristics of the oil and the surrounding geologic and physical forces. The general types of reservoir drive forces (to the limit of general interest in well completions) are:
    1. Solution gas drive - a volumetric displacement where all the driving energy or pressure is supplied by gas expansion as the pressure is reduced and the gas comes out of solution. In reservoirs “above the bubble point”, all the gas is dissolved in the oil and there is no free gas. In these reservoirs, there may be a volume change of the oil as the pressure drops and gas breaks out of solution. Reservoir pressure decreases with fluid withdrawals.
    2. Gas Cap - a volumetric displacement where the oil is “below the bubble point”, i.e., there is free gas or gas saturation in the pores and there may be a gas cap. Reservoir pressure decreases with fluid withdrawals.
   3. Water drive -water influx into the reservoir from edge, bottom or water injection wells can provide very consistent drive pressure to a reservoir. Like the oil, the water moves through the most permeable pathways of the formation towards the pressure drop produced by removal of fluids. The water pushes part of the oil in front, entering some of the pores and displacing the oil. Oil production continues long after the breakthrough of water at the producing well since the formation may contain a number of streaks that have permeability differences an order of magnitude or more. Reservoir pressure may remain the same or drop with fluid withdrawals, depending upon how fast the incoming water replaces the withdrawn fluids.
   4. Reservoir compression through compaction in poorly consolidated, high porosity reservoirs is also a “method” of supplying driving energy but it usually generates serious problems in the reservoir. In these reservoirs, which may often be initially over pressured, the reservoir fluids are aoverburden load supporting element. Withdrawal of the fluids requires the matrix of the formation to support more of the load from the overlying sediments (overburden). In some poorly consolidated or weak formations, the matrix compresses under the load, leading to lower porosity and a continued pressure on the remaining fluids. Although this is a definite form of pressure maintenance, when the porosity is decreased, the permeability also is reduced. Compaction of the pay in massive sections may also lead to subsidence of several feet at the surface -- a critical problem for some offshore rigs and sea level land fields.
   5. Pressure maintenance or sweep projects using water or gas are our methods of increasing recovery. These processes come with many of the same advantages and limitations as their natural counterparts.

Pressures

To a workover engineer, pressure can be a powerful tool or a nightmare. The difference is in how pressure control is handled. The following "short list" of pressures and pressure related terms presents an idea of what and how pressures are important to the workover.
     1. Reservoir Pore Pressure - The pressure of the reservoir fluids, often expressed as a gradient in psilft. The initial reservoir pressure is the pressure at the time of discovery. Fluid withdrawals from a reservoir are made by lowering the pressure in the wellbore. The flow of fluids toward the low pressure creates zones of lower pressure or pressure gradients extending into the reservoir. The reservoir pressure can only be measured at the wellbore in a new well or in a well that has experienced complete buildup.
     2. Flowing Bottom Hole Pressure -This pressure is measured at the productive zone during flow. A value of flowing bottom hole pressure is usually reported with a flow rate or a choke setting. A change in the flow rate will change the flowing bottom hole pressure.
     3. Drawdown - Drawdown is the pressure differential set by the difference of the reservoir pressure and the flowing bottom hole pressure.
     4. Flowing Tubing Pressure - A surface measurement of the pressure in the tubing, prior to the choke, at a particular flow rate. It is equal to the flowing bottom hole pressure minus the hydrostatic pressure exerted by the fluids in the tubing. Because of entrained gas production and gas breakout as the well is produced, it is rarely possible on liquid/gas producers to accurately calculate the flowing bottom hole pressure from the flowing wellhead pressure. Only when the composition of the fluid in the tubing is known can the down hole pressure be calculated.
      5. Shut-in Surface Pressure - Any pressure measured at the surface immediately after a well is shut-in will change as bottom hole pressure builds up toward reservoir pressure and the fluids in the tubing come to an equilibrium. Surface measured shut-in pressures are useful in some buildup tests to assess the productivity of a well.
     6. Productivity Index - The productivity index is a measurement of well flow potential. It is a term generated from a delivery plot of flow rate and pressure from a particular well. It is commonly expressed as a potential flow rate per pressure drop such as barrels per day per psi. By multiplying the PI by the intended drawdown, a flow rate of the well can be predicted. The PI is established by test on the well. It changes with time.
     7. Fracture Breakdown Pressure - A measurement of what pressure is required to hydraulically fracture the rock. The breakdown pressure is usually attained from drilling data, breakdown tests, or fracture stimulations. It is usually expressed as a gradient of pressure per unit of formation depth such as psi/ft.

    8. Fracture Extension Pressure -The pressure necessary to extend the fracture after initiation. Like fracture breakdown pressure, it is relevant to a particular well or field.
    9. Friction Pressure - When fluids are flowed at high rates through a conduit, there is a resistance to flow caused, at least partly, by friction of the fluids at the boundaries of the conduit and by turbulence (mixing) of the fluids. Whether the conduit is pipe or a fracture, friction represents a back pressure. Friction is expressed as pressure at a rate for a unit length of a particular conduit.
    10. Bubble Point Pressure - In a reservoir that contains an undersaturated oil, there will be no gas cap. As the pressure is drawn down, the solution gas will break out of solution. Because of relative permeability and saturation concerns, the occurrence of reaching the bubble point usually coincides with a drop in production.

Pressure Differential

Pressure differential is probably the most important pressure during drilling, completion, workover and production. The differential pressure between the wellbore and the formation dictates which direction fluids will move and at what rate they will move. Additional controls such as reservoir permeability and native and injected fluid viscosity also have an affect, as does the presence of solids in the wellbore fluid when the pressure differential is toward the formation. In general, drilling pressure differential should be as low as possible to minimize formation damage and the amount of fluid invasion from wellbore fluids. However, during any drilling, completion or workover operation, the pressure differential must be toward the wellbore (higher pressure in the wellbore than in the reservoir) when well flow is not wanted. Maintaining pressure differential is the same as maintaining well control. Certain conditions, such as intentional or accidental swabbing caused by swab cups or large-diameter tools, can create low pressures at the bottomhole, even with a column of high pressure fluid above the swab or tool. It is the rate of movement and the diameter difference between the object in the hole and the inside of the hole itself that determine the swab or underbalance loads. Each step of a drilling, completion or workover operation, particularly when tools or  equipment are removed from the hole, should be examined to determine if swab loads can unbalance the pressure differential and swab fluids into the wellbore. During production, pressure differential toward the wellbore is essential for fluid flow. Columns of standing liquids, excessive backpressures or large amounts of solids in the fluids in the wellbore will
act as a check valve, severely limiting production flow into the well. The study of pressure differential and pressure drop is commonly done using a nodal analysis program. These programs compute pressure drops and backpressures on a system, and help identify
those points that may be bottlenecks to good production practices. There are many instances of wells, some even with large-diameter tubing where the tubing has been found to be a “choke” on the production from the well. Changing out the tubing to a larger size in many cases has doubled production from a high capacity well.

Well Temperature

The reservoir at static conditions has a shut-in or reservoir temperature that is characteristic of the depth times the geothermal gradient for that area. A 13,000 ft deep reservoir in one part of the world may have a bottom hole temperature of 1 6OoF, while a similar depth reservoir in a hotter geothermal area may be 360°F.
As the well flows, the bottom hole temperature will drop depending on the type and amount of gas and the pressure drop. The cooling is produced by the expansion of gas. Temperature reductions low enough to freeze water may form ice or “hydrates” in some gas wells while wells with a smaller ratio of gas to liquids will flow hot to surface.

Fluid Properties

The composition of the fluid in the formation, at various points in the tubing and at the surface have major affects on the performance of the well and the selection of production equipment. The following terms are required knowledge to describe the fluid and their changing nature.
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1. Gas-oil-ratio, GOR, the amount of free gas associated with the oil production. The gas may ordinarily be in solution or free gas as in a reservoir with a gas cap. When the gas volume is expressed as a function of the total liquids, the value is the gas-liquid-ratio, GLR. Wells with GLRs above 8000 are considered gas wells, while those with a GOR less than 2000 are labeled oil wells. The wells in between 2000 and 8000 are combination wells. The actual GOR value is usually measured at the surface, its value downhole changes with pressure.
2. Water-oil-ratio, WOR, is the amount of water being produced in ratio to the oil production.
3. Bubble point refers to the pressure that a free gas phase will form in an undersaturated oil. The significance is the addition of another phase that, most likely, will lower the relative permeability.
4. Dew point is the pressure and temperature at which the light hydrocarbon gases, Cs-C,, begin to condense into a liquid. The addition of another phase will lower relative permeability.
5. Cloud point is the temperature in an oil system where paraffin crystals appear (cj8 + fraction begins to solidify).
6. Pour point is the temperature below which the oil will no longer pour.

High Temperature and High Pressure Wells

Wells with pressures over 0.6 psi/ft and temperatures over 300°F are often referred to as HTHP wells
or high temperature, high pressure wells. These wells account for less than 1% of the total wells
drilled, but may cost 5% or more of the total expenditures for drilling and completions. The risk, reward
and cost can all be very great in these types of wells. Very special workover and completion operations
are necessary to adequately complete and produce these wells.