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.