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Petroleum Engineering Handbook
Larry W. Lake, Editor-in-Chief
Volume IV - Production Operations Engineering
Joe Dunn Clegg, Editor
Copyright 2006, Society of Petroleum Engineers
Chapter 5 – Sand Control
Causes of Sand Production
Conventional well completions in soft formations (the compressive strength is less than 1,000 psi) commonly produce formation sand or fines with fluids. These formations are usually geologically young (Tertiary age) and shallow, and they have little or no natural cementation. Sand production is unwanted because it can plug wells, erode equipment, and reduce well productivity. It also has no economic value. Nonetheless, formation sand production from wells is dealt with daily on a global basis. In certain producing regions, sand control completions are the dominant type and result in considerable added expense to operations.
Fluid flow from wells is the consequence of the wellbore pressure being smaller than that in the reservoir. The drag force caused by the flow from large to small pressure is related to the velocity-viscosity product at any point around the well. Hence, when fluids flow toward the wellbore, the tendency is for some of the formation material to flow concurrently with the fluids.
Opposing the fluid forces are the restraining forces that hold the formation sand in place. These consist of natural cementation (compressive strength), friction between sand grains, fluid pressure in the pores of the rock, and capillary forces. The compressive strength of the rock, the primary restraint, is controlled by intergranular cementation that is a secondary geologic process. As a general rule, old sediments are more consolidated than are younger sediments. Young formations commonly have little cementing material and are referred to as being poorly consolidated. Stated another way, they have low compressive strength. Their compressive strengths are usually less than 1,000 psi and may even be so small that their strengths can not be measured. The frictional forces are related to the confining or overburden stresses. The stress that causes the rock to fail includes the mechanical stress that results from the overburden and the drag forces associated from viscous flow of fluids through the rock matrix. The overburden stress is partially supported by the pore pressure, so the net stress (the cause of rock failure, the effective stress) is the difference between the overburden stress and the pore pressure. Capillary forces also can contribute to sand production; there are numerous examples where sand production occurred when water production began. Sand arches form, on occasion, around the perforations. The questions of when and how arches form are related to the flow rate, the compressive strength of the formation, and the size of the sand and the perforations. Fig. 5.1 portrays an arch and the balance between viscous and restraining forces. Unfortunately, sand arches are not stable, and their transient behavior cannot be relied upon for controlling sand production.
The previous discussion is an oversimplification of the problem, and there are other related factors. Think in terms of sand production being related to the production rate, the pressure reduction around the well, and the compressive strength of the formation. If the forces caused by fluid flow exceed the restraining forces, formation sand is produced.
Consequences of Sand Production
The consequences of sand production are always detrimental to the short-long-term productivity of the well. Although some wells routinely experience manageable sand production, these are the exception rather than the rule. In most cases, attempting to manage sand production over the life of the well is not an attractive or prudent operating alternative.
If the production velocity in well tubulars is insufficient to transport sand to the surface, it will begin to fill the inside of the casing. Eventually, the producing interval may be completely covered with sand. In this case, the production rate will decline until the well becomes "sanded up" and production ceases. In situations like this, remedial operations are required to clean out the well and restore productivity. One cleanout technique is to run a "bailer" on a wireline to remove the sand from the production tubing or casing. Because the bailer removes only a small volume of sand at a time, multiple wireline runs are necessary to clean out the well. Another cleanout operation involves running a smaller diameter tubing string or coiled tubing down into the production tubing to agitate the sand and lift it out of the well by circulating fluid. The inner string is progressively lowered while circulating the sand out of the well. This operation must be performed cautiously to avoid the possibility of sticking the inner string inside the production tubing. If the production of sand is continuous, the cleanout operations may be required periodically, as often as monthly or even weekly, resulting in lost production and increased well maintenance costs.
Accumulation in Surface Equipment
If the production velocity is sufficient to transport sand to the surface, the sand may still become trapped in the sebrtor, heater treater, or production flowline. If enough sand becomes trapped in one of these areas, cleaning will be required to allow for efficient production of the well. To restore production, the well must be shut in, the surface equipment opened, and the sand manually removed. In addition to the cleanout cost, the cost of the deferred production must be considered.
Erosion of Downhole and Surface Equipment
If fluids are in turbulent flow, such sand-laden fluids are highly erosive. Fig. 5.2 is a photograph of a section of eroded well screen exposed to a perforation that was producing sand. Fig. 5.3 shows a surface choke that failed because of erosion. If the erosion is severe or occurs long enough, complete failure of surface and/or downhole equipment may occur, resulting in critical safety and environmental problems as well as deferred production.
Collapse of the Formation
Collapse of the formation around the well occurs when large volumes of sand are produced. Apparently, when a void is formed and becomes large enough to inadequately support overlying formations, collapse occurs because of a lack of material to provide support. When the collapse occurs, the sand grains rearrange themselves to create a lower permeability than originally existed. This is especially true for formation sand that has a high clay content or wide range of grain sizes. For a formation with a narrow grain-size distribution (well sorted) and/or very little clay, the rearrangement of formation sand causes a decrease in permeability that is not as severe. In the case of the overlying shale collapsing, complete loss of productivity is probable. In most cases, continued long-term production of formation sand usually decreases the well's productivity and ultimate recovery.
The collapse of the formation particularly becomes critical to well productivity if the formation material fills the perforation tunnels. Even a small amount of formation material filling the perforation tunnels will lead to a significant increase in pressure drop across the formation near the wellbore for a given flow rate. Considering these consequences of sand production, the desired solution to sand production is to control it downhole.
Compaction of the reservoir rock may occur as a result of reduced pore pressure leading to surface subsidence. Examples of subsidence, caused by withdrawals of fluids and reduced pore pressure, are found in Venezuela; Long Beach, California; the Gulf Coast of Texas; and in the Ekofisk Field in the central North Sea, where the platforms sank about 10 ft.
Predicting Sand Production
Predicting whether a well will produce fluids without producing sand has been the goal of many completion engineers and research projects. There are a number of analytical techniques and guidelines to assist in determining if sand control is necessary, but no technique has proven to be universally acceptable or completely accurate. In some geographic regions, guidelines and rules of thumb apply that have little validity in other areas of the world. At the current time, predicting whether a formation will or will not produce sand is not an exact science, and more refinement is needed. Until better prediction techniques are available, the best way of determining the need for sand control in a particular well is to perform an extended production test with a conventional completion and observe whether sand production occurs. Normally, it is not necessary to predict sand production on a well-by-well basis because wells in the same reservoir tend to behave similarly. The prediction required is on a reservoir-by-reservoir basis. However, initial good results may prove misleading, as reservoir and flow conditions change.
Operational and Economic Influences
The difficulty of determining whether sand control is required in a given well is compounded when the well is drilled in a remote area where there is no producing experience and where the various reservoir factors are slightly different from previously exploited regions. Even if the reservoir and formation properties are almost identical to other developments, the operating conditions and risks may be such that different strategies apply. One example might be a subsea project, as opposed to a land development project. Here, the consequences and risks associated with sand production are significantly different because of differing costs and risks associated with remedial well operations; hence, the decision to use a sand-control technique is both an economic and operational decision that must be made with limited data. The decision is complicated by the fact that sand-control techniques, such as gravel packing, are expensive and can restrict well productivity if not performed properly. Therefore, gravel packing cannot be applied indiscriminately when the possibility for sand production from a well is unknown. Making the decision whether to gravel pack is fairly easy if the formation material is either hard (no sand production) or weak (sand production). The difficulty arises when the strength of the formation material is marginal. At that point, the decision normally ceases to be primarily a technical issue but more of an economic and risk management exercise. If there is uncertainty, the conservative approach is to always apply sand-control completions. This obviously will solve the sand production problem but will also increase costs and may reduce well productivity. If sand control was actually unnecessary, the implementation of sand-control completions was a bad economic decision.
The procedure followed by most, to consider whether sand control is required, is to determine the hardness of the formation rock (i.e., the rock's compressive strength). Because the rock's compressive strength has the same units as the pressure difference between the reservoir and the well (the drawdown), the two parameters can be directly compared, and drawdown limits for specific wells can be determined. Research performed in the early 1970s showed that rock failed and began to produce sand when the drawdown pressure was more than about 1.7 times the compressive strength. As an example, formation sand with a compressive strength of 1,000 psi would not fail or begin to produce sand until the drawdown exceeded 1,700 psi. Others use Brinnell hardness as an indicator of whether to apply sand control. The Brinnell hardness of the rock is related to the compressive strength but is not as convenient to use because the units of hardness are dimensionless and cannot be related to drawdown as easily as compressive strength.
The sonic log can be used as a way of addressing the sand production potential of wells. The sonic log records the time required for sound waves to travel through the formation, usually in microseconds. The porosity is related to formation strength and the sonic travel time. Short travel times, less than 50 microseconds, indicate low porosity and hard, dense rock; long travel times, 95 microseconds or greater, are associated with soft, low-density, high-porosity rock. A common technique used for determining whether sand control is required in a given geologic area is to correlate incidences of sand production with the sonic log readings above and below the sand production that has been observed. This establishes a quick screening method for the need for sand control. The use of this method requires calibration against particular geologic formations to be reliable.
Formation Properties Log
Certain well logs, such as the sonic log (previously discussed) and density and neutron devices are indicators of porosity and formation hardness. For a particular formation, a low-density reading indicates high porosity. The neutron logs are primarily an indicator of porosity. Several logging companies offer a formation properties log that uses the results of the sonic, density, and neutron logs to determine if a formation will produce formation material at certain levels of drawdown. This calculation identifies weak and strong intervals; the weaker ones are more prone to produce sand. While the formation properties log has been used for over 20 years, experience has shown that this log usually overpredicts the need for sand control.
The porosity of a formation can be used as a guideline as to whether sand control is needed. If the formation porosity is greater than 30%, the probability of the need for sand control is high because of the lack of cementation. Conversely, if the porosity is less than 20%, the need for sand control will probably be minimal because the sand has some consolidation. The porosity range between 20 to 30% is where uncertainty usually exists. In natural media, porosity is related to the degree of cementation present in a formation; thus, the basis for this technique is understandable. Porosity information can be derived from well logs or laboratory core analysis.
The pressure drawdown associated with production may be an indicator of potential formation sand production. No sand production may occur with small pressure drawdown around the well, whereas excessive drawdown can cause the formation to fail and produce sand at unacceptable levels. The amount of pressure drawdown is normally associated with the formation permeability and the viscosity of the produced fluids. Low viscosity fluids, such as gas, experience smaller drawdowns, as opposed to the drawdown that would be associated with a 1,000-cp fluid produced from the same interval. Hence, higher sand production is usually associated with viscous fluids.
Finite Element Analysis
The most sophisticated approach to predicting sand production is the use of geomechanical numerical models developed to analyze fluid flow through the reservoir in relation to the formation strength. The effect of formation stress, associated with fluid flow in the immediate region around the wellbore, is simultaneously computed with finite element analysis. While this approach is by far the most rigorous, it requires an accurate knowledge of the formation's strength around the well in both the elastic and plastic regions where the formation begins to fail. Input data on both regions are difficult to acquire with a high degree of accuracy under actual downhole conditions. This is the major difficulty with this approach. The finite element analysis method is good from the viewpoint of comparing one interval with another; however, the absolute values calculated may not represent actual formation behavior.
The effect of time on the production of formation sand is sometimes considered to be an issue; however, there are no data that suggest that time alone is a factor. There have been undocumented claims that produced fluids could possibly dissolve the formation's natural cementing materials, but the data are not substantiated.
Predicting when multiphase fluid flow will begin can also be an aid. Many cases can be cited where wells produced sand free until water production began, but produced unacceptable amounts afterwards. The reason for the increased sand production is caused by two primary phenomena: the movement of water-wet fines and relative permeability effects. Most formation fines are water wet and, as a consequence, immobile when a hydrocarbon phase is the sole produced fluid because hydrocarbons occupy the majority of the pore space. However, when the water saturation is increased to the point that water becomes mobile, the formation fines begin the move with the wetting phase (water), which creates localized plugging in the pore throats of the porous media. Additionally, when two-phase flow occurs, increased drawdown is experienced because two phases flowing together have more resistance to flow than either fluid alone. These relative permeability effects can increase the drawdown around the well by as much as a factor of 5 per unit of production. See the chapter that discusses relative permeability in the General Engineering section of this Handbook. The result of fines migration, plugging, and reduced relative permeability around the well increases the drawdown to the point that it may exceed the strength of the formation. The consequences can be excessive sand production. The severity of fines migration varies from formation to formation and whether gas or liquid is being produced.
There are several techniques available for minimizing sand production from wells. The question of which one to use arises. The choices range from simple changes in operating practices to expensive completions, such as sand consolidation or gravel packing. The sand-control method selected depends on site-specific conditions, operating practices and economic considerations. Some of the sand-control techniques available are maintenance and workover; rate exclusion; selective completion practices; plastic consolidation; high energy resin placement; resin coated gravel; stand-alone slotted liners or screens; and gravel packing.
Maintenance and Workover
Maintenance and workover is a passive approach to sand control. This method basically involves tolerating the sand production and dealing with its effects, if and when necessary. Such an approach requires bailing, washing, and cleaning of surface facilities routinely to maintain well productivity. It can be successful in specific formations and operating environments. The maintenance and workover method is primarily used where there is minimal sand production, low production rates, and an economically viable well service.
Restricting the well's flow rate to a level that reduces sand production is a method used occasionally. The point of the procedure is to sequentially reduce or increase the flow rate until an acceptable value of sand production is achieved. The object of this technique is to attempt to establish the maximum sand-free flow rate. It is a trial-and-error method that may have to be repeated as the reservoir pressure, flow rate, and water cut change. The problem with rate restriction is that the maximum flow rate required to establish and maintain sand free production is generally less than the flow potential of the well. Compared to the maximum rate, this may represent a significant loss in productivity and revenue.
Selective Completion Practices
The goal of this technique is to produce only from sections of the reservoir that are capable of withstanding the anticipated drawdown. Perforating only the higher compressive strength sections of the formation allows higher drawdown. The high compressive strength sections will likely have the most cementation and, unfortunately, the lowest permeability. While this approach might eliminate the sand production, it is flawed because the most valuable reserves will not be in communication with the well.
Plastic consolidation involves the injection of plastic resins that are attached to the formation sand grains. The resin subsequently hardens and forms a consolidated mass, binding the sand grains together at their contact points. If successful, the increase in formation compressive strength will be sufficient to withstand the drag forces while producing at the desired rates. The goal of these treatments is to consolidate about a 3-ft radius around the well without appreciably decreasing the permeability of the rock.
Three types of resins are commercially available: epoxies, furans (including furan/phenolic blends), and phenolics. The resins are in a liquid form when they enter the formation, and a catalyst or curing agent is required for hardening. Some catalysts are "internal" because they are mixed into the resin solution at the surface and require time and/or temperature to harden the resin. Other catalysts are "external" and are injected after the resin is in place. The internal catalysts have the advantage of positive placement because all resin will be in contact with the catalyst required for efficient curing. A disadvantage associated with internal catalysts is the possibility of premature hardening in the work string. The amounts of both resin and catalyst must be carefully chosen and controlled for the specific well conditions. Epoxy and phenolics can be placed with either internal or external catalysts; however, the rapid curing times of the furans (and furan/phenolic blends) require that external catalysts be used.
There are two types of plastic consolidation systems. These are called "phase separation" systems and "overflush" systems. Phase separation systems contain only 15 to 25% active resin in an otherwise inert solution. The resin is preferentially attracted to the sand grains, leaving the inert portion that will not otherwise affect the pore spaces. These systems use an internal catalyst. Accurate control of the plastic placement is critical because overdisplacement will result in unconsolidated sand in the critical near-wellbore area.
Phase separation consolidation may be ineffective in formations that contain more than 10% clays. Clays, which also attract the resin, have extremely high surface area in comparison to sands. The clays will attract more resin and because phase separation systems contain only a small percentage of resin, there may not be enough resin to consolidate the sand grains.
Overflush systems contain a high percentage of active resin. When first injected, the pore spaces are completely filled with resin, and an overflush is required to push the excess resin away from the wellbore area to re-establish permeability. Only a residual amount of resin saturation, which should be concentrated at the sand contact points, should remain following the overflush. Most overflush systems use an external catalyst, although some include an internal catalyst.
All plastic consolidations require a good primary cement job to prevent the resin from channeling behind the casing. Perforation density should be a minimum of four shots per foot to reduce drawdown and improve the distribution of plastic; however, each perforation must be treated. Shaley zones should not be perforated because fluids are difficult to place in these low-permeability strata. Clean fluids are essential for plastic consolidation treatments because all solids that are in the system at the time of treatment will be "glued" in place. The perforations should be washed or surged, workover rig tanks should be scrubbed, and fluids should be filtered to 2 microns. Work strings should be cleaned with a dilute HCl acid containing sequestering agents, and pipe dope should be used sparingly on the pin only. A matrix acid treatment, which includes HF and HCl, is recommended for dirty sandstones to increase injectivity.
Both phase separation and overflush systems require a multistage preflush to remove reservoir fluids and make the sand grain oil wet. The first stage, generally diesel oil, serves to displace the reservoir oil. Epoxy resins are incompatible with water; therefore, isopropyl alcohol follows the diesel to remove formation water. The final stage is a spacer (brine) that prevents the isopropyl alcohol from contacting the resin.
Plastic consolidation leaves the wellbore fully open. This becomes important where large OD downhole completion equipment is required. Also, plastic consolidation can be done through tubing or in wells with small-diameter casing. For most applications, the problems associated with plastic consolidation outweigh the possible advantages. The permeability of a formation is always decreased by plastic consolidation. Even in successful treatments, the permeability to oil is reduced because the resin occupies a portion of the original pore space and is oil wet. The amount of resin used is based on uniform coverage of all perforations. However, perforation plugging or permeability variations often cause some perforations to take more plastic than others. In systems that use an external catalyst, there is no sand control in areas that are not contacted by both resin and catalyst.
The primary difficulty in using resin systems is attaining complete and even placement of the chemicals in the formation. In lenticular formations, plastic placement may be uneven because of widely varying permeabilities, and some zones are likely to be untreated. These untreated intervals may break down during subsequent production, and the well will sand up. For this reason, plastic consolidation is suitable for interval lengths less than 10 to 15 ft. Longer intervals can be treated using packers to isolate and treat small sections of the zone at a time, but such operations are difficult and time consuming. Plastic consolidation treatments also do not perform well in formations with permeabilities less than about 50 md. Low permeabilities preclude injecting resins under matrix conditions and cause permeability reductions by the plastic that substantially reduce residual permeability (i.e., well productivity). The resins soften at a temperature greater than 255°F and may not provide sufficient strength at elevated temperature.
Plastic consolidation was used extensively in the late 1950s through the mid-1970s in the Gulf of Mexico; however, this technique currently represents far less than 1% of all sand-control completions worldwide. The reasons for decreased usage include lack of suitable candidates, the placement difficulties already described, as well as tight regulations on the handling of the chemicals, which are generally quite toxic (with the furans being the least toxic of the three). These treatments tend to be costly. The main disadvantage of plastic systems in current operations is its high cost and limited completion interval length for an effective treatment, 15 ft or less. The latter excludes most wells. Because of its current limited use, service companies have difficulty maintaining trained crews.
High-Energy Resin Placement
As previously discussed, one of the main reasons for the lack of acceptance of chemical consolidation techniques has been difficulties in placing the resin uniformly across the entire target interval and restricted length. The uneven coverage is more severe in intervals greater than about 15 ft long. Causes for this are typically attributed to differences in injectivity caused by incomplete perforation clean-up during underbalanced perforating jobs or permeability variations in the formation interval length. See the chapter that discusses under- and overbalanced drilling in the Drilling Engineering section of this Handbook. Also see the chapter in the Production Operations Engineering section that discusses underbalanced perforating.
High-energy resin placement addresses some of these problems.  The technique injects the resin rapidly under highly overbalanced conditions. The resin is surged into the formation at rates that will place the resin before the formation has a chance to fail. Another benefit to the rapid resin placement is that the technique appears to be less affected by permeability contrasts than the matrix treatments. This characteristic leads to more uniform placement over a long perforated interval. This method is still experimental.
Three methods are available for creating the high overbalance pressures that can assist resin placement—propellant gas fracturing, overbalanced perforating, and overbalanced surging. The overbalanced perforating method is currently the preferred method.
Propellant Gas Fracturing. The use of propellant gas fracturing tools involves the conversion of solid propellant by chemical reaction into a gas in the target zone of a wellbore. The chemical propellant is changed into combustion gases by one of two different mechanisms: detonation or flame propagation. Detonation involves a reaction characterized by a shock wave that moves rapidly through the interval to be treated. This shock wave, traveling at velocities between 15,000 and 25,000 ft/sec, induces pressures ranging from 400 to 4,000,000 psi, with pressurization rates up to 100,000 psi. The high-pressure surge places the resin more evenly in long formation intervals where conventional plastic consolidation, pumped at matrix, is impractical.
The reaction products are contained in place by the liquid column in the wellbore above the tool. The rapid generation of gas forces the resin placed in the annular space surrounding the tool out of the perforations and into the formation. For this process, the casing must be in good condition and properly cemented to be successful. Perforations must be clean and clear of debris, and all debris should be removed from the wellbore. Only clean sands should be perforated. Finally, if sand has been produced, the perforations should be prepacked with gravel prior to the treatment, which may be difficult.
The process involved in this type of a treatment is to first inject a preflush of mutual solvent to remove water from the target interval. Furan resin is then placed across the perforations, and the gas-generating propellant tool is placed across the entire perforated interval. Nitrogen overbalance is applied to the work string, and the propellant device is fired to inject resin above fracture pressure. The resin is then followed with an acid post-flush to harden the resin.
An advantage to this system is that resin will be placed in all perforations immediately across from the location of the gas generator tool. However, if multiple tool runs are required to treat an interval longer than about 36 ft, movement of the tool will make it difficult to hold the resin in position. The two other methods, overbalanced perforating and overbalanced surging, are designed to alleviate the problem of maintaining the resin in position.
Overbalanced Perforating or Surging. High-overbalanced perforating resin placement may be used if the well has not been previously perforated. If a well has existing perforations, the interval can be prepacked, and then the resin can be placed with a high-pressure surge.
The composition of the resin solution is furfuryl alcohol resin solvent, a coupling and wetting agent. The resin catalyzes with an acid to form a furan plastic. The resin solution is positioned across an interval of planned perforations. A more dense fluid may proceed below the resin to fill a portion of the wellbore below the zone of interest. A lower density fluid may follow above the resin in the wellbore to keep the resin from floating up above the zone of interest. This technique can ensure more accurate placement of resin across the soon to be perforated interval. Operationally, the pressure in the wellbore fluid, at the depth to be perforated, is increased to a substantially greater level than the pore pressure in the formation. The applied pressure before perforating may be higher than the formation fracturing pressure. Wireline through tubing or casing guns, or tubing conveyed perforating, can all be used for perforating. Resin is forced into the new perforations upon perforating with the overbalanced pressure. Acid is injected into the perforations to convert the liquid resin into a strong plastic that will consolidate the sand.
While the high-energy resin placement techniques offer an advantage over conventional matrix plastic consolidation methods, they are not widely used, and this system is plagued by many of the disadvantages of plastic consolidation—high cost, low success, and lack of longevity. The results of high-energy plastic treatments generally have tended to be disappointing.
Resin-coated gravel treatments can be pumped in two different ways. The first is a dry, partially catalyzed phenolic resin-coated gravel. Thin resin coating is about 5% of the total weight of the sand. When exposed to heat, the resin cures, resulting in a consolidated sand mass. The use of resin-coated gravel as a sand-control technique involves pumping the gravel into the well to completely fill the perforations and casing. The bottomhole temperature of the well, or injection of steam, causes the resin to complete the cure into a consolidated pack. After curing, the consolidated gravel-pack sand can be drilled out of the casing, leaving the resin-coated gravel in the perforations. The remaining consolidated gravel in the perforations acts as a permeable filter to prevent the production of formation sand. The main use of resin-coated gravel is in prepacked screens, which is discussed later.
Wet resins (epoxies or furans) can also be used. To pump these systems, the well is usually prepacked with gravel; then, the resin is pumped and catalyzed to harden the plastic. After curing, the consolidated plastic-sand mixture is drilled out of the well, leaving the resin-coated sand in the perforations.
Although simple in concept, using resin-coated gravel can be complex. First, and most important, a successful job requires that all perforations be completely filled with the resin-coated gravel, and the gravel must cure. Complete filling of the perforations becomes increasingly difficult, as zone length and deviation from vertical increase. Second, the resin-coated gravel must cure with sufficient compressive strength. While resin-coated systems were used extensively after their development, their use today is limited. Experience with them has shown good initial success but poor longevity, as most wells do not produce sand-free for extended periods of time.
Stand-Alone Slotted Liners or Screens
Slotted liners or screens have been used as the sole means of controlling formation sand production. In this service, they function as a filter. Unless the formation is a well-sorted, clean sand with a large grain size, this type of completion may have an unacceptably short producing life before the slotted liner or screen plugs with formation material. When used alone as sand exclusion devices, the slotted liners or screens are placed across the productive interval, and the formation sand mechanically bridges on the slots or openings in the wire-wrapped screen. Bridging theory and laboratory tests show that particles will bridge on a slot, provided the width of the slot is less than two particle diameters. Likewise, particles will bridge against a hole if the perforation diameter does not exceed about three particle diameters.
The slot width, or the screen gauge, is sometimes sized to be equal to the formation sand grain size at the 10-percentile point of the sieve analysis. The theory is that because the larger 10% of the sand grains will be stopped by the openings of the screen, the larger sand will stop the remaining 90% of the formation. The bridges formed will not be stable and may break down from time to time when the producing rate is changed or the well is shut in. Because the bridges can fail or break down, resorting of the formation sand can occur, which, over time, tends to result in plugging of the slotted liner or screen. This design fails for fine-grained sand formations because the slot width is smaller than those available for commercial slotted liners. Wire-wrapped screens can meet the design, but their width is so small that plugging and production reduction is virtually assured. When this technique is used to control formation sand, the slotted liner or screen diameter should be as large as possible to maximize inflow area and minimize the amount of resorting that can occur. Another potential disadvantage of both slotted liners and screens in high-rate wells is the possibility of erosional failure of the slotted liner or screen before a bridge can form.
Using a slotted liner or screen without gravel packing is generally not a good sand-control technique because, in most cases, the screen will eventually restrict well rates because of plugging. There are isolated situations where this use has been successful in openhole completions in high-permeability, well-sorted formations. Selected North Sea wells have performed well. Screens or slotted liners should be avoided in cased-hole completions as the sole sand-control technique because, when the annulus and perforations become filled with formation sand, production rates decrease drastically.
Gravel packing consists of placing a screen or slotted liner in a well opposite the completion interval and placing gravel concentrically around it. The gravel is actually large-grained sand that prevents sand production from the formation but allows fluids to flow into the well. The slotted liner or screen retains the gravel. The gravel is sized to be about 5 to 6 times larger than the median formation sand size. Gravel packing creates a permeable downhole filter that allows the production of the formation fluids but restricts the entry and production of formation sand. Schematics of an openhole and cased-hole gravel pack are shown in Fig. 5.4. If the gravel is tightly packed between the formation and the screen, the bridges formed are stable, which prevents shifting and resorting of the formation sand. If properly designed and executed, a gravel pack will maintain its permeability under a broad range of producing conditions.
Gravel packing is currently the most widely used sand-control technique for completing wells. More than 90% of all sand-control completions are gravel packs. Because of its flexibility, almost any well at any deviation can be gravel packed. The exception is tubingless completions where clearances do not permit the use of conventional tools. Some tubingless completion gravel packs have been performed, but their success was poor.
Guidelines for Selecting Sand Control
There are many alternatives for sand control. Each alternative has its advantages and disadvantages. Even techniques that are not widely used may have a potential application in which its use might be superior to others. As mentioned before, gravel packing is currently the most widely used technique. The cost to gravel pack is directly related to rig costs. Gravel-packed completions from floating drilling rigs may cost in excess of U.S. $2 million. However, should remedial operations be required on a gravel pack, the screen and completion assembly must be removed from the well, which could involve a lengthy fishing job and related problems. Sand consolidation and resin-coated sand are attractive for tubingless completions because no mechanical equipment is left in the hole; however, low permeability, small-interval length, high temperatures, and completion longevity (wells sanded up or low productivity) all present problems with the plastic systems. The right technique must be selected for the well completion at hand. As a first approach, assume that the well will be gravel packed. If it is not appropriate, for whatever reason, review other alternatives.
A gravel pack is simply a downhole filter designed to prevent the production of unwanted formation sand. The formation sand is held in place by properly sized gravel pack sand that, in turn, is held in place with a properly-sized screen. To determine what size gravel-pack sand is required, samples of the formation sand must be evaluated to determine the median grain size diameter and grain size distribution.  The quality of the sand used is as important as the proper sizing. The American Petroleum Institute (API) has set forth the minimum specifications desirable for gravel-pack sand in API RP58, Testing Sand Used in Gravel-Packing Operations. 
Formation Sand Sampling
The first step in gravel-pack design is to obtain a representative sample of the formation. Failure to analyze a representative sample can lead to gravel packs that fail because of plugging or the production of sand. Because the formation sand size is so important, the technique used to obtain a formation sample requires attention. With knowledge of the different sampling techniques, compensation can be made in the gravel-pack sand size selection, if necessary.
Produced Samples. A produced sample of the formation sand is easily contaminated before it reaches the surface. Although such a sample can be analyzed and used for the gravel-pack sand size determination, produced samples will probably have a smaller median grain size than the median of actual formation sand. The well's flow rate, produced fluid characteristics, and completion tubular design influence whether a particular size is produced to surface or settles to the bottom of the well. In many cases, the larger sand grains settle, so a sample that is produced to the surface has a higher proportion of the smaller-size sand grains. This is the reason that the surface sample is not a good representation of the various sizes of formation sand. Also, the transport of sand grains, through the production tubing and surface flow lines, may result in broken sand grains, causing the presence of more fine and smaller grains.
Bailed Samples. Samples collected from the bottom of a well using wireline bailers are also relatively easy to obtain, but these too are probably unrepresentative of the size of the actual formation sand. Bailed samples are generally biased to the larger-size sand grains, assuming that more of the smaller grains are produced to surface. Bailed samples also may be misleading in terms of grain size distribution. When closing the well in to obtain a sample, the larger sand grains settle to the bottom of the well first, and the smaller sand grains fall on top of the larger ones. This results in a sorting of the formation sand grains into a sample that is not representative the formation sand. The use of bailed samples may result in the design of larger than required gravel-pack sand that can result in sand production (small formation particles passing through the gravel pack) or plugging of the gravel pack (small formation particles filling the spaces between the gravel-pack sand grains).
Sidewall Core Samples. Sidewall core samples are obtained by shooting hollow projectiles from a gun lowered into the well on an electric line to the desired depth. The projectiles remain attached to the gun with steel cables, so that when the gun is pulled from the well, the projectiles are retrieved with a small formation sample inside. Taking sidewall core samples is generally included in the evaluation stages of wells in unconsolidated formations; these are the most widely used sample types for gravel-pack sand design. Although more representative than produced or bailed samples, sidewall core samples can also give imprecise results because the volume in each sidewall sample is small. When the projectiles strike the face of the formation, localized crushing of the sand grains occurs, producing broken sand grains and generating more fine particles. The core sample also contains drilling mud solids that can be mistaken for formation material. Experienced lab analysts can separate the effects of crushing and mud solids prior to evaluating the sample, thus improving the quality of the results.
Conventional Core Samples. The most representative formation sample is obtained from conventional cores. In the case of unconsolidated formations, rubber sleeve conventional cores may be required to assure sample recovery. Although conventional cores are the most desirable formation sample, they are not readily available in many wells because of the cost of coring operations. Coring in sand-producing formations is also plagued with poor recovery. If available, small plugs can be taken under controlled circumstances at various sections of the core for a complete and accurate median formation grain size and grain-size distribution determination.
Other Samples. From time to time, operators have no formation sample. In this event, rely on any of the samples from offset wells. If the formation of interest has gravel-pack completions in nearby fields, rely on these. If there is still no information, select a relatively small gravel that will control most formation sand, or consult an expert.
A sieve analysis is a laboratory routine performed on a formation sand sample for the selection of the proper-sized gravel-pack sand. A sieve analysis consists of placing a formation sample at the top of a series of screens that have progressively smaller mesh sizes downwards in the sieve stack. After placing the sieve stack in a vibrating machine, the sand grains in the sample will fall through the screens until encountering a screen through which certain grain sizes cannot pass because the openings in the screen are too small. By weighing the screens before and after sieving, the weight of formation sample, retained by each size screen, can be determined. The cumulative weight percent of each sample retained can be plotted as a comparison of screen mesh size on semilog coordinates to obtain a sand size-distribution plot, as shown in Fig. 5.5. Reading the graph at the 50% cumulative weight gives the median formation grain size diameter. This grain size, often referred to as d50, is the basis of gravel-pack sand size-selection procedures. Table 5.1 provides a reference for mesh size vs. sieve opening.
Fig. 5.5—Sand size distribution plot from sieve analysis.
If possible, a sample should be taken every 2 to 3 ft within the formation, or at least at every lithology change. The minimum size of the formation sample required for sieve analysis is 15 cm3. Sieving can be performed either wet or dry. In dry sieving (the most common technique), the sample is prepared by removing the fines (i.e., clays) and drying the sample in an oven. If necessary, the sample is ground with a mortar and pestle to ensure individual grains are sieved rather than conglomerated grains. The sample is then placed in the sieving apbrtus that uses mechanical vibration to assist the particles in moving through and on to the various mesh screens. Wet sieving is used when the formation sample has extremely small grain sizes. In wet sieving, water is poured over the sample while sieving to ensure that the particles do not cling together.
Gravel-Pack Sand Sizing
There have been several published techniques for selecting a gravel-pack sand size to control the production of formation sand. The most widely used sizing criterion provides sand control when the median grain size of the gravel-pack sand, D50 , is no more than six times larger than the median grain size of the formation sand, d50 . The upper case D refers to the gravel, while the lower case refers to the formation sand. The basis for this relationship was a series of core flow experiments in which half the core consisted of gravel-pack sand and the other half was formation sand. The ratio of median grain size of the gravel-pack sand and median grain size of the formation sand was changed over a range from 2 to 10 to determine when optimum sand control was achieved.
The experimental procedure consisted of measuring the pack permeability with each change in gravel size and comparing it to the initial permeability. If the final permeability was the same as the initial permeability, it was concluded that effective sand control was achieved with no adverse productivity effects. If the final permeability was less than the initial permeability, the formation sand was invading and plugging the gravel-pack sand. In this situation, sand control may be achieved, but at the expense of well productivity. Fig. 5.6 illustrates the results of core flow experiments for a particular gravel/sand combination. As shown in the plot, the permeability of the pack increases up to a median gravel/sand size ratio of 6 but decreases as the ratio increases further. The permeability decreases to a minimum as a 10:12 ratio is reached; then, it increases. The explanation for this behavior is that the permeability increases as the gravel/sand size ratio increases up to a ratio of about 6, which reflects the increasing permeability of the larger gravel (i.e., at a gravel/sand ratio of one, the gravel is the same size as the formation sand). At a gravel/sand size ratio of 6, the formation sand grains bridge on, rather than into the pore structure of the gravel, which is the correct gravel size that provides the highest permeability. However, as the gravel size becomes larger and the ratio increases, the formation begins to bridge within the pore structure of the gravel, thereby decreasing the pack permeability. At a ratio of 10:12, the formation sand has moved well into the pores, decreasing the permeability substantially. As the gravel becomes larger, a reversal occurs because now the formation sand can move both into and through the pore structure of the gravel. At ratios in excess of 15, the formation sand can flow through the gravel with ease. As Fig. 5.6 indicates, at gravel/sand ratios less than 10:12, there is sand control, whereas at ratios larger than 12, there is no sand control.
Fig. 5.6—Effect of gravel-sand ration on sand control permeability.
In practice, the proper gravel-pack sand size is selected by multiplying the median size of the formation sand by 4 to 8 to achieve a gravel-pack sand size range, in which the average is six times larger than the median grain size of the formation sand. Hence, the gravel pack is designed to control the load-bearing material; no attempt is made to control formation fines that make up less 2 to 3% of the formation. This calculated gravel-pack sand size range is compared to the available commercial grades of gravel-pack sand. Select the available gravel-pack sand that matches the calculated gravel-pack size range. In the event that the calculated gravel-pack sand size range falls between the size ranges of commercially available gravel-pack sand, select the smaller gravel-pack sand. Table 5.2 contains information on commercially available gravel-pack sand sizes.
Note that this technique is based solely on the median grain size of the formation sand with no consideration given to the range of sand grain diameters or degree of sorting present in the formation. The sieve analysis plot, discussed earlier, can be used to obtain the degree of sorting in a particular formation sample. A near vertical sieve analysis plot represents good sorting (most of the formation sand is in a very narrow size range) vs. a highly sloping plot, which indicates poorer sorting as illustrated by curves "A" and "D," respectively, in Fig. 5.5. A sorting factor, or uniformity coefficient, can be calculated as
|Cμ||=||sorting factor or uniformity coefficient,|
|d40||=||grain size at the 40% cumulative level from sieve analysis plot,|
|d90||=||grain size at the 90% cumulative level from sieve analysis plot.|
If Cμ is less than 3, the sand is considered well sorted (uniform); from 3 to 5, it is nonuniform, and if greater than 5, it is highly nonuniform.
The productivity of a gravel-packed well depends on the permeability of the gravel-pack sand and how it is placed. To ensure maximum well productivity, one should use high quality gravel-pack sand. API RP58, Testing Sand Used in Gravel Packing Operations, establishes rigid specifications for acceptable properties of sands used for gravel packing. These specifications focus on ensuring the maximum permeability and longevity of the sand under typical well production and treatment conditions. The specifications define minimum acceptable standards for the size and shape of the grains, the amount of fines and impurities, acid solubility, and crush resistance. Only a few naturally occurring sands are capable of meeting the API specifications without excessive processing. These sands are characterized by their high quartz content and consistency in grain size. Table 5.3 gives the permeability of common gravel-pack sand sizes conforming to API RP58, Testing Sand Used in Gravel Packing Operations, specifications (data from Sparlin; Gurley, Copeland, and Hendrick; and Cocales).
Once the sieve analysis has been performed and plotted, the remainder of the gravel-pack sizing can be performed graphically. The gravel-pack sand size is determined by multiplying the median formation grain size by 6. This value is the median gravel grain size. With a straight edge, construct the gravel curve so that its uniformity coefficient, Cμ, is 1.5. The actual gravel size can be determined by the intercept of gravel curve with the 0 and 100 percentile values. Select to the nearest standard gravel size. The screen slot width is typically half the smallest gravel size selected but should not exceed 70% of the smallest grain diameter. While it may appear that this design is conservative, it will not restrict productivity and allows for variances in screen tolerances. The diameter of the screen should allow for at least 0.75-in. clearance from the casing inside diameter (ID). Fig. 5.7 is an example gravel-pack design.
Fig. 5.7—.Effect of gravel-sand size ratio on sand control and productivity.
Gravel-Pack Sand Substitutes
Although naturally occurring quartz sand is the most common gravel-pack material, many alternatives exist. These include: resin-coated sand, garnet, glass beads, and aluminum oxides. Each of these materials offers specific properties that are beneficial for given applications and well conditions. The cost of the materials ranges from 2 to 3 times the price of common quartz sand.
Slotted Liners and Wire-Wrapped Screens
The slotted liner or screen is the mechanical device that contains the gravel-pack sand in an annular ring between it and the casing wall or open hole. Fig. 5.8 shows a schematic of its function in an openhole gravel pack.
Fig. 5.8—Openhole gravel-pack schematic.
Slotted liners are made from tubulars by saw-cutting slot configurations, as shown in Fig. 5.9. Slot widths are often referred to in terms of gauge. Slot or screen gauge is simply the width of the opening in inches multiplied by 1,000. For instance, a 12-gauge screen has openings of 0.012 in.
The machining consists of cutting rectangular openings with small rotary saws. Routine slot widths are 0.030 in. or larger. The minimum slot width that can be achieved is about 0.012 in. Slots that cut less than 0.020 in. in width involve high costs because of excessive machine downtime to replace broken saw blades that overheat, warp, and break.
The single-slot staggered, longitudinal pattern is generally preferred because the strength of the unslotted pipe is preserved. The staggered pattern also gives a more uniform distribution of slots over the surface area of the pipe. The single-slot staggered pattern is slotted with an even number of rows around the pipe with a typical 6-in. longitudinal spacing of slot rows.
The slots can be straight or keystone shaped, as illustrated in Fig. 5.10. The keystone slot is narrower on the outside surface of the pipe than on the inside. Slots formed in this way have an inverted "V" cross-sectional area and are less prone to plugging because any particle passing through the slot at the outside diameter (OD) of the pipe will continue to flow through, rather than lodging within the slot. While the slotted liners are usually less costly than wire-wrapped screens, they have smaller inflow areas and experience higher pressure drops during production. Slotted liners also plug more readily than screens; they are used where well productivity is small and economics cannot support the use of screens.
The length of the individual slots is measured on the ID of the pipe. Usual practice dictates 1½-in. long slots for slot widths of 0.030 in. and under, 2-in. long slots for slot widths between 0.030 to 0.060 in., and 2½-in. long slots for slot widths of 0.060 in. and larger. Slot width tolerance is generally ± 0.003 in. for widths of 0.040 in. and wider and ± 0.002 in. for widths less than 0.040 in.
The primary advantage of a slotted liner over wire-wrapped screens is usually cost; however, small gauge, high-density slot patterns may cost as much as wire-wrapped screens. The disadvantages of the slotted liner are limited flow area (2 to 3%, creating a low tolerance to plugging) and minimum available slot size (approximately 0.012 in.). Slot widths that are less than 0.020 in. and cut in standard carbon steel-pipe grades can rust and will either close or reconfigure the slot opening so that they do not function properly unless they are coated, protected, or stored indoors before use.
Wire-wrapped screens offer another alternative for retaining the gravel in an annular ring between the screen and the formation. Wire-wrapped screens have substantially more inflow area than a slotted liner, as Fig. 5.11 illustrates. The screen consists of an outer jacket that is fabricated on special wrapping machines that resemble a lathe. The shaped wire is simultaneously wrapped and welded to longitudinal rods to form a single helical slot with any desired width. The jacket is subsequently placed over and welded at each end to a supporting pipe base (containing drilled holes) to provide structural support. This is a standard-commodity design manufactured by several companies. A schematic of the screen construction is shown in Fig. 5.12. Screen tolerances are typically plus 0.001 and minus 0.002 in.; hence, a specified 0.006-in. slot could vary in slot width from 0.004 to 0.007 in.
Fig. 511.—Comparison of effective inlet areas (20-gauge screen).
Because these designs have been used for more than 40 years in worldwide oilfield operations, a great deal is known about the performance of wire-wrapped screens. The typical pipe-base screen fabrication consists of a grade 316L stainless steel jacket placed over a N-80 pipe base; however, other metals can be specified as required for site-specific applications. The inflow area of screens varies from about 6 to 12% (or higher), depending on the slot opening. Screens with the smallest slot openings are typically 6 gauge (0.006 in.). For large gravel, 10 to 20 mesh, screen slot openings are about 18 gauge (0.018 in.).
A version of the wire-wrapped screen is the rod-based screen that consists of the jacket only; however, rod-based screens may have additional heavier rods and a heavier wire wrap than the jackets used on pipe-base screens to provide additional strength. Rod-based screens are commonly used in shallow water-well completions that typically range from a few hundred to maybe a 1,000 ft in depth. Hence, they do not require the strength that is gained by installing the screen jacket over a pipe base. Screen diameters range from 1.5 to 7 in. in diameter (or larger). This is the diameter of the pipe base. The actual screen diameter is slightly larger (i.e., the actual OD of a 3.5-in. screen is about 4 in.).
Prepacked screens are a modification of wire-wrapped screens; they actually represent a modular gravel pack. They consist of a standard screen assembly with a layer of resin-coated gravel (consolidated) placed around it that is contained in an annular ring supported by a second screen (dual-screen prepack) or outer shroud (single-screen prepack). The resin coating is a partially cured phenolic plastic. Being dry, the resin-coated gravel can be handled like ordinary gravel. After prepacking the screen, the complete unit is heated to cure and harden the resin. The thickness of the gravel layer can be varied to meet special needs. The screens with the lowest profiles are those that contain an annular pack between the jacket and the pipe base. This screen has a thin lattice screen wrapped around it to prevent gravel from flowing through the drill holes in the pipe base before consolidation. Examples of prepacked screens are in Fig. 5.13. Prepacked screens have been used with gravel packs instead of standard wire-wrapped screens and in stand-alone applications in horizontal wells. While the prepacked screens have been used in stand-alone service, experience has shown that they are highly prone to plugging, consequently restricting productivity. The inflow area of these screens is about 4 to 6% of the surface area. The exact amount depends on the slot opening and the size of the gravel.
Flow Capacities of Screens and Slotted Liners
Fig. 5.14 shows the pressure drop associated with commercial wire-wrapped screens. Because all have similar designs, there is little difference in performance from one manufacturer to another. These flow capacity tests were performed using water containing no plugging material. The data indicate that all screens have exceptionally high flow capacities. Flow testing with slotted liners revealed that their flow capacity was related to the slot density rather than the screen diameter. Their flow capacities are typically less than half that of wire-wrapped screens with the same diameter. Note that the flow rates were measured in increments of B/D/ft of screen. For flow rates that are typical of most wells, the pressure loss through the screen is negligible, provided that they are not plugged. Slotted liners are more easily plugged than wire-wrapped screens because the slots are usually cut brllel to each other. On the other hand, wire-wrapped screens are fabricated with keystone-shaped wire that allows a particle to pass through the screen if it can traverse the minimum restriction at the OD of the screen. The keystone design can be observed in Fig. 5.10.
Fig. 5.14—Flow capacity of 12-gauge screens with 20/40 U.S. mesh gravel.
Tensile/Collapse Strengths of Wire-Wrapped and Prepacked Screens
Tensile strength test results performed on screens and slotted liners in standard testing equipment showed that standard pipe-base screens have higher tensile ratings than rod-base screens. Testing demonstrated that yielding occurred in the pipe body as well as the coupling. As a consequence, when yielding in the connection caused a thread to separate, the test was terminated. The tensile strength of standard pipe-base screens was about twice that of the rod-base screens.  For conservative designs, the tensile strength should be the lesser of 65% of the pipe body or the published joint pull-out strength.
Individual tests demonstrated collapse failures as high as 6,000 to 9,000 psi; however, this represented the simultaneous failure of the screen and the pipe base; screens have a collapse rating of about 3,500 psi, which is the rating for the jacket.
Proprietary Screen Designs
Proprietary designs were originally developed for stand-alone installations in horizontal wells rather than a gravel-packed completion; however, gravel-pack screen applications should not be ruled out. They are also applicable in this service. Proprietary designs are premium designs that surpass the performance of either a standard wire-wrapped screen or a prepacked screen in their ability to resist plugging and erosion and are equipped with torque-shouldered connections to permit rotation. Because horizontal completions typically consist of a thousand to several thousand feet of completion interval, the main issue is the susceptibility of a particular design to plug with time rather than the flow capacity. These new designs have increased inflow areas to as much as 30% of the surface area of the screens. The materials used and the designs differ from conventional wire-wrapped screens. They consist of designs with lattice, Dutch weave, porous membrane, sintered metal, and corrugated weave filtration sections. The logic used in these designs was that because these screens have inflow areas of 30% compared to about 5% with prepacked screens, their longevity should be extended by about a factor of six when operating under similar downhole conditions. Other issues involve the ability to run the screen without creating damage that would either prevent sand control or restrict productivity. To address this concern, most of the proprietary designs have an outer shroud to protect the screen during installation. Proprietary connections are typically used for horizontal service because of their high strength and the ability to rotate if necessary.
Sintered Metal Screens. The sintered metal screen design was initiated in gravel-pack use in about 1990. The design consists of placing a sintered metal sleeve that is 0.15 to 0.25 in. thick over a drilled pipe base. The sintered metal sleeve contains approximately 30% flow area. The sleeve acts as the filtration medium, while the pipe base provides tensile strength and collapse resistance. Fig. 5.15 is a schematic of the screen design.
Tensile strength and collapse resistance of this design should be about the same as that for wire-wrapped screens. For conservative designs, the tensile strength capabilities should be the about 65% or the lesser of either the published pipe strength or the joint pull-out of the coupling. The collapse rating should be similar to published values for wire-wrapped screens of about 3,500 psi.
Porous Metal Membrane Screens. This screen design consists of multiple layers (3 or 4) of porous metal membrane (PMM), which contains about 30% open area through variable-sized pore openings. These are between an underlying drainage and overlying protecting mesh screen. They are placed concentrically between a drilled pipe base and a perforated outer shroud. The filter medium for the screen is sintered metal powder that is pressed against a stainless steel lattice screen to provide structural support for the filtration medium. A schematic of the screen's construction is illustrated in Fig. 5.16. Test data from the manufacturer show tensile strength testing performed to 110k lbf and a collapse test to about 7,000 psi performed on 2 7/8-in. screens, both of which reflect the strength of the pipe base. These data are similar to values for commodity wire-wrapped screens. The tensile strength rating should be less than 65% of the pipe body or connection because physical properties of the screen jacket and perforated shroud should not contribute to these properties significantly.
Shrouded Multilayer Screens. This screen design consists of three layers of media that form the jacket, which are placed concentrically around a drilled pipe base. The base wrap for the jacket consists of a round stainless steel wire-wrapped support that serves as a drainage layer for the overlying filtration medium. The shroud is placed concentrically over the filtration medium. See Fig. 5.17 for a schematic of the design.
The purpose of the base wrap or inner jacket is for support for the overlying filtration medium against high differential pressure. The wrap also promotes using the entire surface area of the filtration medium that optimizes plugging resistance. The openings in the base wrap are typically about 25 microns or larger than the filtration medium to provide secondary sand control. The filtration medium provides pore throat openings that assist in maximizing the inflow area that develops a more permeable filter cake. The design of the filtration medium, a Dutch weave, redirects the flow through it to minimize erosion and extend screen life. The design being offered is rated at a uniform pore-throat opening sizes from 110 to 230 microns. The inflow area for this design is also about 30% of the surface area of the screen. The outer shroud protects the inner filtration section during installation in the well and assists in redirecting the flow stream during production so that erosion of the filtration section is minimized. The strength rating for this screen is a tensile rating of 65% of the pipe body or the published joint pull-out strength and a jacket collapse rating of 3,500 psi.
Plugging and Erosion Tests on Proprietary and Commodity Screens
Prepacked screen designs are more susceptible to plugging than other designs. This stems from their depth filter design. Standard wire-wrapped screens are a surface filter, which are not as susceptible to plugging but are more prone to erosion. Certain proprietary designs are better at resisting plugging and erosion than others. The best designs have large inflow areas and redirected flow through the screen to minimize erosion.
Gravel-Pack Completion Equipment and Service Tools
There is a myriad of gravel-pack systems available to handle virtually any conceivable well condition. Fig. 5.18 illustrates typical gravel packs for cased and openhole completions. These employ crossover gravel packing equipment that is state-of-the-art in the industry today. Washdown and reverse circulation methods are other alternatives that are less expensive and are to be used when costs will not support crossover equipment.
Gravel-pack completion equipment is the equipment that remains in the well after the gravel placement operations are complete. The equipment discussed next does not represent all the types of available equipment, but it does represent a typical gravel-pack completion. Certain well conditions may require compromises in the type and design of gravel-pack equipment that can be used. Another important concept is that there may be several, yet equally effective, ways to complete a well.
The first step in installing a gravel-pack completion is to establish a base on which the screen will rest. In cased-hole completions, the most common type base is a sump packer. The sump packer is normally run into the well on an electric wireline before perforating and is set a specified distance (5 to 10 ft) below the lowest planned perforation. The distance below the perforations must accommodate the length of the seal assembly and production screen overlap.
Although sump packers are the preferred gravel-pack base, other options such as a bridge plug or cement plug can be used. In openhole completions, provisions for a debris sump or logging access can be achieved, but these are not routine and may not be feasible in some situations. Therefore, the gravel-pack base is normally a bull plug on the bottom of the screen. The types of common gravel-pack bases are illustrated in Fig. 5.19.
The seal assembly is required to establish a seal in the bore of the sump packer to prevent gravel-pack sand from filling the bottom of the well during gravel packing. In the case of multiple gravel packs, the seal also provides for zonal isolation. The seal assembly used to engage the sump packer is normally a snap latch type or other type holddown.
The purpose of the gravel-pack screen is to create an annulus between the screen and the casing/open hole and to hold the gravel in place during production. As discussed earlier, there are several different types of screens.
Screen Centralization. Filling the annulus between the screen/casing (or open hole) with gravel-pack sand is essential to the control of formation sand production. To ensure that the annulus is filled completely around the screen, centralization of the screen is required. In cased-hole completions, weld-on, blade-type centralizers are normally used. The blades are approximately 6 in. long and are cut from a 0.25- to 0.50-in.-thick plate or steel. The edges of the centralizers are beveled to ensure easy run-in. The centralizers consist of four blades welded to the screen base pipe 90° apart to result in an OD approximately 0.25 in. under the ID of the well's casing. The centralizers are spaced 15 to 20 ft apart and can be positioned at the top, bottom, and/or middle of a screen joint as required.
In openhole gravel packs, centralization is accomplished with bow-spring centralizers. These centralizers consist of a top and bottom collar connected with 4 to 6 steel spring bows. The bows can be compressed (i.e., the centralizer is elongated) for running through restricted IDs. When the centralizer enters a larger ID, the bows attempt to expand to their original position, resulting in a restoring force or centralization. Sufficient centralizers are required such that the combined restoring force is capable of lifting the weight of the screen in the given hole conditions. Computer programs are available for determining optimum centralizer spacing for a specific bow-spring centralizer, hole size, and deviation. See API Spec. 10D, Specification for Bow-Spring Casing Centralizers.
The purpose of blank pipe is to provide a reservoir of gravel-pack sand above the screen to ensure that the screen remains completely packed in the event of pack settling. During gravel-pack operations, it is possible for minor voids in the annulus pack to occur. In fact, gravel packing with viscous gel transport fluids commonly produces voids, particularly opposite the short lengths of blank pipe between screen joints. Depending on deviation angle, pack settling shortly after gravel placement may fill the voids. It is important to have a sufficient reserve of gravel-pack sand available for this process to occur without uncovering the top of the screen.
Blank Pipe Centralization. As with the screen, the blank pipe must be centralized to ensure even gravel distribution in the blank and casing annulus. Weld-on centralizers are normally used in both cased-hole and openhole completions because the blank pipe is almost always positioned inside the casing. Bow-spring centralizers can be used if desired or required.
Blank Pipe Length. Several rules of thumb exist for determining the length of blank pipe. Perhaps the most scientific method would be to recognize that voids will occur within the length of screen wherever nonscreen regions exist (i.e., at screen joint connections and above the gravel pack). A long-standing guideline for gravel reserve has been to maintain a minimum of 30 ft of packed gravel in the blank pipe above the top of the screen when packing with brine. When viscous fluids are used, blank lengths may be as much as twice the screen length for short completion intervals. This allows for additional settling with these fluids when the gel breaks.
Tell-Tale Screens. Tell-tale screens are short screen sections that are sometimes used to assist with gravel placement and determine when the gravel pack is complete. Their benefit is questionable. There are two types of tell-tale screens: the upper and lower versions.
Upper tell-tale screens are used primarily with brine-pack systems. They are typically located about 30 ft above the main gravel-pack screen. Their function is to indicate, by an increase in pressure, when the dehydrated gravel has reached the tell-tale location. This assures that there is the desired amount of gravel reserve.
Lower tell-tale screens are used when gravel packing with viscous fluids. Their purpose is to assist in ensuring that the gravel slurry reaches the bottom of the gravel pack before the slurry dehydrates. The gravel-pack tools are usually in the lower circulating position when the tell-tale is used in these installations.
Shear-Out Safety Joint
A shear-out safety joint is located just above the blank pipe. It consists of a top and bottom sub connected by shear screws. This device is incorporated in most gravel pack completion assemblies to allow retrieval of the gravel-pack packer and the gravel-pack extension independently of the blank pipe and screen. The joint is parted with straight tension to shear the screws while pulling the packer with a packer-retrieving tool.
Knock-Out Isolation Valve
The knock-out isolation valve is a mechanical fluid-loss device that prevents completion fluid losses and subsequent damage to the formation after performing the gravel pack. The downward closing flapper in the valve is held open by the gravel-pack service tools (normally the washpipe) during the gravel pack. When the service tools are removed from the valve, the flapper closes, preventing fluid loss to the formation. The gravel-pack service tools can be removed from the well and the completion tubing run. When the well is producing, the flapper will open. Alternatively, the flapper is made of a breakable material and can be broken hydraulically or mechanically before producing the well.
Gravel-pack extensions are used with the gravel-pack packer and service tools to provide a flow path from the tubing above the packer and to the screen/casing annulus below the packer. The gravel-pack extension consists of the upper extension (which contains flow ports for the gravel pack fluids), sealbore (sized to match the bore of the gravel-pack packer), and lower extension (to house the gravel-pack crossover tool throughout its range of motion). The length of the gravel-pack extension is designed to work with a particular gravel-pack packer and crossover tool. Gravel-pack extensions are available in two types: perforated or sliding sleeve versions.
At the top of the gravel-pack assembly is a gravel-pack packer. The packer may be permanent or retrievable. However, retrievable type packers are recommended for gravel packing. A retrievable packer expedites workover activities without the potential cost and risk of milling a permanent packer. The retrievable packers used for gravel packing are usually sealbore type packers that can also be used for production; therefore, the packer must be designed for the temperature, pressure, and environmental conditions present in the well.
Gravel-Pack Service Tools
Gravel-pack service tools are the equipment necessary to perform the gravel pack; they are removed from the well after gravel packing. In most cases, the type of gravel-pack equipment used dictates the service tools required for a gravel pack. Further discussion of the service tools is discussed next.
Hydraulic Setting Tool. The hydraulic setting tool is a hydraulic piston that generates the force required to set the gravel-pack packer. It is attached to the top of the crossover tool and has a sleeve shouldered against the setting sleeve of the packer. A setting ball is dropped to the ball seat in the crossover tool to plug off the ID of the work string. Applied pressure to the work string acts on a piston in the hydraulic setting tool to force the sleeve down to compress the slips and packing element of the packer. Special versions of the setting tool are available, which allow for rotation and high-circulating rates while running the gravel-pack assembly.
Gravel-Pack Crossover Tool. The gravel-pack crossover tool creates the various circulating paths for fluid flow during gravel packing. The crossover tool consists of a series of molded seals surrounding a gravel-pack port midway down the tool and a return port near the top of the tool. A concentric tube (washpipe) design in the crossover tool along with the gravel-pack packer and gravel-pack extension allow fluid pumped down the work string above the packer to "cross over" to the screen/casing annulus below the packer. Similarly, return fluids flowing up the washpipe and below the packer can "cross over" to the work string/casing annulus above the packer.
Gravel-pack crossover tools typically have three positions: squeeze, circulating, and reverse circulating, as illustrated in Fig. 5.20. The squeeze position is located by positioning to seal the return ports. The squeeze position allows all fluids pumped down the work string to be forced into the formation. It is used to perform squeeze gravel-pack treatments and/or inject acid treatments into the formation. The circulating position is located by picking the crossover tool up approximately 18 in. above the squeeze position. The circulating position works with a properly sized washpipe to provide a flow path to circulate gravel-pack sand to completely fill the screen/casing annulus. The fluids flow down the work string into the crossover tool, out the gravel-pack extension, down the screen/casing annulus into the screen, up the washpipe into the crossover tool again, and up the work string/casing annulus. Special, high-rate, erosion-resistant crossover tools are available for high-rate brine or frac-pack completions.
Washpipe. Washpipe is run below the gravel-pack crossover tool inside the blank pipe and screen to ensure that the return circulation point for the gravel-pack carrier fluid is at the bottom of the screen. The washpipe assists in placing gravel-pack sand at the bottom of the screen and packing from the bottom up. The end of the washpipe should be as close to the bottom of the screen as possible.
Maximizing the washpipe OD increases the resistance to flow, preferentially into the washpipe/screen annulus. The greater resistance to flow forces the gravel-pack transport fluid to flow in the screen/casing annulus and carry the gravel-pack sand to the bottom of the well. That causes the gravel packing of the screen/casing annulus to be more complete. The optimum ratio of washpipe OD to screen base pipe ID should be approximately 0.8. Achieving this ratio in some screen sizes will require the use of special flush-joint washpipe connections.
Well Preparation for Gravel Packing
Well preparation includes many activities to ensure that the well is completed properly. Some of these items and activities include: appropriate drilling practices, cleanliness, completion fluids, perforating, perforation cleaning, acidizing, and specifications for rig and service company personnel.
The productivity of a cased- or openhole gravel-packed completion is determined in part by the condition of the reservoir behind the filter cake, the quality of the filter cake, and the stability of the wellbore. Given this, it can be said that the completion begins when the bit enters the pay. Thus, it follows that the goal of drilling is to maintain wellbore stability while minimizing formation damage.
Maintaining Wellbore Stability
Wellbore stability in the form of washouts, hole collapse, and fracturing is an effect of large drilling fluid loss, inadequate overbalance, and/or reaction between filtrate and the formation. But, for whatever reason, instability affects both cased- and openhole completions because it can cause loss of the wellbore. Thick cement sheaths in washed-out sections result in poor to no perforation penetration and the lack of cement can make sand placement difficult. Hole collapse can prevent running screens to the bottom of the hole, and failure, in the form of fracturing or collapse, can stop an openhole gravel pack, should failure occur while the pack is in process.
Because stability is an effect of the reaction between the drill-in fluid and the formation, filtrate, filter cake, weight, and rheology become key parameters in building a drill-in fluid. These variables usually can be addressed by using polymers and fluid-loss agents in a brine-based fluid containing a properly-sized bridging agent like that contained in special drill-in fluids.
Formation damage, expressed quantitatively in the form of skin, depends on the filtrate used, particle damage, and, for openhole gravel packs, filter cake quality. Skin, in turn, is a reflection of poor productivity; it is expensive to remove or bypass. Preservation of reservoir pore throats requires keeping particles out of pores, minimizing filtrate loss, and employing a filtrate that is compatible with rock and reservoir fluids.
With openhole completions, filtrate must be nondamaging, but it is generally overlooked in cased-hole completions. Frequently, it is assumed that any damage caused by filtrate will be bypassed with perforating. Looking at the occasions when reservoirs are exposed to moderate to high fluid losses, often expressed as a "thirsty mud," it is possible to have filtrate invade 1 to 3 ft from the wellbore. If the filtrate is incompatible with reservoir rock and fluid, there will be a damaged ring beyond which it may be impossible for perforations to penetrate. For openhole completions, the quality of the filter cake is also as important as the other requirements. Because the cake must be gravel packed into place, it is necessary that the cake be thin and friable and have a low breakout pressure.
Again, as with the wellbore stability issue, filtrate and filter cake become key parameters. Proper selection of a filtrate brine base, along with polymers and fluid loss agents containing a properly-sized bridging agent, usually meets these needs.
Cleaning the Casing, Openhole, and Work-String
Cleanliness may be one of the most important considerations for gravel packing. Because a gravel pack represents the installation of a downhole filter, any action that promotes plugging the gravel pack is detrimental to well productivity. Many advances have been made in improving the cleanliness of gravel-pack operations, particularly in completion fluids. However, in spite of the fact that clean completion fluids are used, the lack of cleanliness in the casing, work string, lines, pits, and other equipment is a source of potential formation damage. While cleaning the well and rig equipment can be expensive, it is not as expensive as lost productivity or having to rework the entire completion because proper cleaning was neglected in the beginning.
Casing. Reverse circulation is the preferred method of circulation for cleaning the casing. The recommended annular velocity is a minimum of 130 ft/min for casing shoe deviations less than 60° and 300 ft/min for wellbore deviations greater than 60°. Reverse circulation is more effective than conventional circulating, as material is moved downhole with the gravity where it is more efficiently circulated to the surface because of higher velocities in the work string than in the annulus. For an openhole completion, reverse circulation permits cleaning the casing to specifications before addressing the open hole. Planning for a work string that will permit reverse circulation at reasonable bottomhole pressures is required.
Mechanical, hydraulic, and chemical cleaning agents should be employed to clean the casing. Mechanical agents are usually in the form of casing scrapers; most hydraulic agents are push pills and filtered brine. Casing sweeps provide a chemical wash to address polymers, oil, and/or solids adhering to the casing wall.
As a mechanical agent, scrapers remove cement and scale, which will not hinder a bit but will impede a packer. It is prudent to run casing scrapers to the bottom or at least through the interval to be perforated. For openhole completions, the scraper should be run to within 100 ft of the shoe or at least past the proposed packer seat. In displacing the drilling/drill-in fluid, a push pill is pumped first, followed by a casing sweep that is followed by filtered brine. (See Fig. 5.21.) Push pills serve as a hydraulic piston by creating a sharp interface between mud and casing sweep. The casing sweep removes polymers and solids adhering to the casing wall. The filtered brine provides turbulence to help remove and wash material from the casing.
Push pill volumes should at least be equal to a volume of 300 ft of work string-casing annulus and have the same density as the drill-in fluid and a yield point that is 1.5 to 2.0 times that of the drill-in fluid. Thus, they are easily made from a portion of the drill-in mud by the addition of a viscosifier to raise the yield point. Casing sweeps depend on the chemical employed to remove solids and polymer and, to be effective, will require some contact time at turbulent rates. Calcium hypochlorite (65% active) at 1.5 lbm/bbl and a 5-min contact time effectively removes polymers and fluid-loss agents.
Open Hole. As with the casing, reverse circulation is the preferred method of circulation for an open hole. With the casing cleaned and displaced as previously discussed, all attention can be focused on cleaning the open hole. Wellbore losses and instability can easily be detected and repaired if necessary, and any unrecovered material will be pushed to the bottom out of the way. Recommended annular velocity is 300 ft/min at any deviation to scour the filter cake in preparation for gravel packing and to clean the hole.
Push pills should be used to displace the drill-in fluid from the open hole. The pill should be spotted in the casing and work string annulus above the open hole using forward circulation; then, the work string is run to the bottom and the push pill and drill-in fluid displaced from the open hole with filtered brine using reverse circulation. (See Fig. 5.22.) Push pills are sized, as previously discussed in the section on casing cleaning.
Work String. The work string should be sized to permit reverse circulation. It should always be run open ended to minimize backpressure on the formation. The work string contains the same types of debris associated with the casing; however, unlike casing, both the inner and outer surfaces of the work string must be clean because completion fluid is circulated along both surfaces. The work string is usually not a major problem if it has been in use before the completion. Work strings just delivered from storage should be carefully inspected for scale, rust, mill varnish, and other debris. Scraping the work string is usually not as good an option as for the casing, but visual inspections, before it is run into the well, are encouraged to ensure that the string is in good mechanical condition and clean. As a minimum, a "rabbit or drift" with a diameter slightly less than the drift diameter of the work string helps to loosen scale and other debris, as well as providing assurance of the internal diameter of the work string. Once the work string is clean, every effort must be made to keep it clean.
A common source of contamination of the gravel pack is thread dope lubricant. One should use thread dope lubricant sparingly and only on the pin ends during the completion phase. Eliminate the use of thread dope completely on the final run in the hole just before gravel packing the well. Pickling the work string with a pipe dope solvent and a 10% HCl solution before starting a gravel pack is a must. As with any solvent, there is a required contact time and wash rate to dissolve lubricant and carry material out of the work string. Consider the use of a dedicated clean work string strictly for gravel packing, if a number of wells are to be completed.
Although they are sometimes ignored, tanks and lines are a common cause of damaging materials, particularly when the rig that drilled the well is used for completing the well. Tanks must be thoroughly scraped and jetted to ensure that any residual solids from the drilling fluids are removed. When possible, tanks should be dedicated to completion fluids when a drilling program involves drilling numerous wells requiring gravel packs. Casing sweep chemicals and seawater are recommended for removing debris from rig lines.
If properly filtered brine is used as per the following discussion on filtration, the hole is displaced as recommended, and surface facilities are cleaned, it is easy to obtain returned brine that has less than 20 NTU (nephelometric turbidity units) throughout the entire gravel-pack operation. Again, this is only possible if all of the steps are followed. NTU are measured with turbidity meters that should be carefully calibrated.
As stated earlier, gravel-pack completion fluids must be sufficiently clean in order that suspended particles do not plug or reduce the permeability of the formation, perforations, or gravel-pack sand. To achieve a clean fluid requires filtration. Completion fluids are typically filtered to 2 or 10 microns, but in some cases, they are filtered to 1 micron. The fluid can be filtered by either a diatomaceous earth (DE) filter upstream in combination with a cartridge filter unit downstream or with a cartridge filter unit alone. A schematic of the filtration system is shown in Fig. 5.23. The DE filter unit does a majority of the filtering before the fluid arrives at the cartridge filter unit. Because DE is less expensive than cartridge filters, the use of a DE filter with a cartridge filter downstream is more economical than a cartridge filter unit alone. This is especially true if the completion fluid is dirty, which is usually true at some point during the completion or if large volumes of fluid are required, as in the case of gravel packing.
DE filters are not absolute filters, so a wide variety of particle sizes are capable of "bleeding through" the filter. The DE filter packing itself also will bleed through the filter. DE is capable of plugging the formation and is not acid soluble; therefore, a DE filter should always be used with a downstream cartridge filter to stop the DE and provide additional fluid filtration.
Cartridge filter units can use either nominal or absolute filter cartridges. The nominal filters are typically wound elements designed for bulk solids removal using deep bed filtration. The absolute filters have pleated elements that rely on surface filtration to retain specific size particles. Absolute filters are rated on their efficiencies by their beta rating. The beta rating is defined as the ratio of the concentration of a given particle size entering the filter to the concentration of the same size particle exiting the filter. Commonly used filters have beta ratings from 100 to 5,000. The beta rating depends on flow rate. As an example, a filter that will stop a 2-micron particle at 1 gal/min (gpm) might not stop the same particle at 10 gpm. Also, beta ratio depends on the particle size considered. A cartridge will have a high beta ratio (removal efficiency) for large particles, but a lower beta ratio for smaller particles. For most oilfield operations, filters with beta ratings of 1,000 are all that are required because these remove 99.9% of the particulate material from the fluid passed through it. The equation for calculating removal efficiency from the beta ratio is written as
|Rex||=||removal efficiency for particle size "x" (percent),|
|β||=||beta ratio for particle size "x."|
Most completion fluids used for gravel packing are filtered to 2 microns with a removal efficiency of 99.9% or better. Care should be taken while filtering to ensure that the pressure differential through the cartridges does not exceed the cartridge manufacturer's recommendation (typically 30 psi); otherwise, collapse of the cartridge and fluid bypass may occur, destroying the filter's efficiency. Filtration of naturally viscous fluids is difficult because of increased pressure drop required to flow a viscous fluid through the cartridge. If polymers are used, they must be thoroughly sheared to remove unhydrated clusters or "fish eyes." These fluids should be filtered after shearing. Occasionally, you may have to deal with extremely dirty fluids. If time permits, it is advisable to allow the dirty fluid to stand undisturbed overnight to allow solids to settle to the bottom of the holding tank. The clean fluid can then be decanted from the top of the tank and filtered without having to deal with the large volume of settled particles. Oil entrained in the completion fluid also can present filtration problems.
Completion and Gravel-Pack Fluids
The normal sources of completion fluids are produced brine, seawater, or commercially mixed clear brines. In addition to being clean, the fluids used in the well completion must be compatible with the formation and formation fluids. Of particular concern is clay swelling. Additionally, the fluid should be compatible (that is, not cause precipitation on mixing) with formation water. The candidate completion fluids should be tested in the laboratory to ensure their compatibility with the formation and formation fluids because an incompatible completion fluid can cause permanent formation damage.
The overriding design criterion for a good completion fluid is the hydrostatic requirements to maintain well control. Fluid density can be controlled by adding several water-soluble salts such as sodium chloride, sodium bromide, potassium chloride, ammonium chloride, calcium chloride, calcium bromide, zinc bromide and lithium bromide. The densities of these fluids range from 8.33 to as high as about 20 lbm/gal, values that are comparable with the densities of drilling muds. All fluids have their advantages and disadvantages, which depend on the density of the fluid required. High density fluids are expensive.
The fluids used for gravel packing can be water or oil based. The water-based fluids are usually the most desirable, have a higher density, and are more flexible to use than the oil-based systems. Because of this, the water-based fluids are more commonly used. The simplest water-based fluid used for gravel packing is the completion brine itself. Crude oil has been used in the past in preference to water because it was cheaper; however, with the increase in the cost of oil, its use has been largely discontinued in preference to the water-based systems. Crude oil is still a valid alternative in extremely water sensitive formations and when small densities are needed; however, oil is inflammable, and extra precautions are needed to prevent spills.
Perforating for Gravel Packing
Perforating consideration for gravel packing is primarily an exercise in selecting the perforating gun and charge configuration that will provide adequate inflow from the reservoir. Remember that the gravel must be placed in the perforation tunnels. If the gravel porosity is about 35%, this equates to filling 65% of the cross-sectional area of the perforations with gravel. Large-diameter perforations, greater than 0.75 in., fired in high-shot density guns, 12 shots/ft or higher, are the desired configuration to provide a high inflow area. The gravel-pack charges have typical penetrations of 8 to 10 in., which is all that is required for these completions. Deep penetration charge designs are ineffective because they produce an insufficient perforation area for gravel packs. They should be avoided except in special situations, such as having to penetrate two strings of casing, etc. Whether the perforating is performed with wireline or tubing-conveyed guns depends on interval length and other factors. Short, one-gun run completions favor the wireline guns. Intervals with completion lengths greater than 30 ft favor tubing conveyed guns because the entire interval can be perforation underbalanced with a single run of the perforating assembly. Other than these broad guidelines, one should use standard perforating procedures.
With an impingement pressure approaching 15,000,000 psi, the perforation jet pushes through the casing and cement and into the formation, where it compacts the materials immediately surrounding the perforation. Because the cement and the formation are crystalline, they are compacted. This creates a zone of reduced permeability at the boundary of the perforation that is caused by the high impingement pressure. It is often referred to as the compacted zone. The compacted zone can be up to ½ in. thick and can have a permeability that is substantially less than that of the bulk formation, which can significantly restrict well productivity.
Additionally, the shaped charge creates debris that is deposited in the perforation. The metal from the housing is typically steel and not readily soluble in acid. The liner is usually made of compressed copper that may form a copper slug called a "carrot" after the perforation is created. The carrot may remain inside the hollow carrier and be retrieved, or it could remain in the perforation tunnel or become lodged in the perforation entrance hole in the casing, which is the worst case.
The perforating debris and the compacted zone must be removed to maximize well productivity. Failure to remove the debris and compacted zone can reduce the potential production rate. The methods available for perforation cleaning include acidizing, washing, backsurging, underbalanced perforating, and fracturing. Some recently developed techniques are also available to assist in the operation of cleaning the perforations such as "debris-free" charges. Such charges are not actually debris-free but result in fine-grained material that is acid soluble and easily flowed from the well.
Acidizing. Acidizing perforations involves injecting a predetermined type and volume of acid into the perforations after they have been created to dissolve any acid-soluble material. In most cases, perforating debris is not highly soluble in acid; therefore, acidizing is more effective and better applied when used with other cleaning techniques. Some considerations critical to acidizing are the compatibility of the acid with the formation, the volume of acid being pumped, and the need for uniform placement of the acid into the perforations.
Acid solubility tests should be performed on a formation sample to select the most effective acid. This is important because the acid may actually damage the formation instead stimulating it. The volume of acid to pump is typically determined by the number of perforations and the length of the perforated interval.
Poor placement of acid produces variable and inconsistent results, possibly leading to a decrease in productivity. Ideally, each perforation would receive an equal volume of acid. In reality, the acid tends to flow into the perforations that are unrestricted and do not especially need cleaning. Meanwhile, other perforations that do need cleaning take in little or no acid. To achieve uniform placement of acid into the perforations, use an acid "diverter" to attempt to divert acid from the permeable perforations to the damaged perforations. The usual technique involves pumping several stages of acid separated by diverter slurries consisting of viscous gel and gravel-pack sand. The diverter will flow into the most permeable perforations and fill them with gravel-pack sand. The combination of gravel-pack sand and the high viscosity of the gel reduce the ability of the perforation to accept fluid. The next acid stage should then flow into the other, more resistive perforations, allowing for a more uniform treatment. This technique is referred to as a "staged acid treatment" or an "acid prepack." It can be performed immediately after underbalanced tubing-conveyed perforating (for best results) or just before performing the gravel pack. This will be reviewed further in the discussion on prepacking perforations.
The goal of washing is to establish communication between several sets of perforations to effectively remove the perforation debris and compacted zone from the well. Unfortunately, perforation washing is commonly performed incorrectly because rig crews may not take time to follow correct procedures. Washing perforations involves running an opposing cup-type tool or pinpoint packers into the well after perforating. The cup tool seals on the inside of the casing and allows a circulation path through the tool and out ports located between the opposing cups. The tool's cup spacing is usually about 1 ft to focus the washing operation over a short interval. The washing consists of pumping filtered, unviscosified completion fluid at the largest rate possible without breaking down the perforations, as Fig. 5.24 illustrates. Washing should be conducted at the smallest acceptable fluid overbalance.
Fig. 5.24—Washing perforations with wash tool.
Backsurging is the running of a surge tool in the well after perforating. The tool has a chamber that contains air at atmospheric pressure. A packer is set, and the lower valve to the chamber is opened to expose the formation to atmospheric pressure, thereby surging the perforation to expel damage. Unfortunately, the technique does not open all plugged perforations and may require several runs in the well to achieve results. Each run is a special trip.
Underbalanced Tubing Conveyed Perforating
Underbalanced-tubing-conveyed perforating is popular for cleaning perforations. It is similar to backsurging but only requires a single trip in that the desired underbalance is set by the amount of fluid in the work string. Upon gun detonation, the formation is immediately surged in proportion to the amount of underbalance. General guidelines for underbalance in unconsolidated sandstone reservoirs are to use 500 psi for oil wells and 1,000 psi for gas wells. In a given field, trial-and-error testing can establish the best underbalance for site-specific conditions.
A relatively new technique is to bypass perforating damage instead of using a cleaning or removal technique. Extreme overbalance perforating is used to perforate and then fracture the formation. The process has been used primarily on consolidated formations with relatively large compressive strengths.
Frac packing and water fracs also have been successfully used in unconsolidated formations to bypass perforating, drilling, and cementing damage. This procedure is discussed later.
Fluid Loss Control
Fluid loss control is a common consideration when completing unconsolidated formations with a gravel pack, especially in high-permeability formations. In addition to the potential formation damage caused by fluid loss, there is particular anxiety when expensive fluids are involved or when completion fluid reserves are low. The amount of fluid loss that can be tolerated tends to be site-specific, but when losses exceed about 30 bbl/hr, there is concern. Loss rates of 20 to 40 bbl/hr on an offshore rig that has only 100 bbl of reserve fluid is serious. In the latter situation, the rig has about 3 to 4 hours before it either runs out of fluid or has to replenish its supply. Another problematic situation is when fluid losses are high and the completion brine is costly. Hence, managing and minimizing fluid losses can be a major problem.
The normal methods for controlling fluid loss include: reduced hydrostatic pressure, viscous polymer gels, graded solid particles, and mechanical means. The type of fluid-loss control that is recommended often depends on what phase of the completion process is being executed. Because completion begins as soon as the bit enters the pay and continues through the running of production tubing, excessive fluid loss may become an issue while drilling the reservoir, during openhole gravel packing (especially for a highly deviated hole), immediately after perforating, after prepacking, and after gravel packing.
When selecting a fluid-loss control technique, the current condition of the well, operations still needing completion, and available remedial techniques for elimination of the deleterious effects of fluid loss control must all be considered. These considerations may lead to different fluid-loss control techniques being used throughout the completion and must not be taken lightly.
Gravel Placement Techniques
Gravel packing consists of installing a downhole filter in the well to control the entry of formation material but allow the production of reservoir fluids. The gravel-packed completion is perhaps the most difficult and complex routine completion operation because it consists of many interrelated completion practices. There are two primary objectives for gravel packing a well. First, the annulus between the screen and casing must be packed with gravel. Filling the annulus with properly-sized gravel ensures that the formation sand is not produced to surface. The second objective is to pack each perforation with gravel. Filling the perforations with gravel is the key to obtaining high productivity. In an unconsolidated formation, any perforation that is unfilled with gravel will fill with formation sand and severely restrict productivity from such perforations. The following discussion deals with filling the annulus. Perforation packing is discussed later.
The crossover circulating technique is the most common method used to place the gravel around the screen. The gravel-pack equipment and service tools allow circulating the gravel down the work string above the packer and into the screen/casing annulus below the packer. The returns flow up the washpipe and cross over into the work string/casing annulus. The fluid used to transport the gravel can either leak off to the formation or be circulated or reversed out of the hole through the washpipe (as illustrated in Fig. 5.25), depending on the position of the service tools.
A variety of fluids has been used as gravel transport fluids such as brine, oil, diesel, crosslinked gels, clarified xanthum gum (XC) gel, hydroxyethylcellulose (HEC) gel, and foam. The most commonly used fluids have been brine and HEC gel. Gravel packs performed with brine are referred to as water/brine packs or conventional packs. Gravel packs performed with HEC gel transport fluids are referred to as slurry packs, gel, or viscous packs. Table 5.4 is a comparison of HEC gel and brine characteristics that are important to their use as gravel transport fluids. When using HEC, the gravel is suspended by the gel and settles slowly because of the high fluid viscosity. When using brine as a transport fluid, the gravel settles quickly because of the low viscosity. Hence, higher pump rates may be required to cope with particle settling when brines are used.
The earliest gravel packs were performed in shallow, vertical wells, typically by simply pouring gravel into the tubing/casing annulus and allowing the gravel to settle around a screen. Some screens were even washed into place after the gravel was placed. The technique is still employed in water wells but now is seldom used in oil/gas wells. As equipment and technology improved, gravel packing of oil/gas wells was accomplished by mixing sand in brine and pumping the mixture into the hole. Brine represents the simplest of the transport fluids. Before the early 1960s, brine was the most commonly used gravel-pack fluid because other fluid systems had not been developed at that time.
The early equipment used to mix brine and gravel was inefficient and resulted in the "slugging" of gravel into the hole, as opposed to a consistent brine-to-gravel mix ratio. The brine was seldom filtered, and no specifications were in place to ensure the quality of gravel-pack sand. Overall rig housekeeping was poor, and the perforating techniques available were limited to low-shot density, small-diameter guns that produced entrance-hole diameters that were less than 0.5 in. in diameter. The combination of all these factors resulted in unsatisfactory gravel-pack completions that were commonly damaged.
In the late 1960s, research efforts by several companies focused on improving gravel packing. The research efforts culminated in the introduction of viscosified gravel transport fluids, HEC being the fluid of choice. One of the most attractive features of viscous fluids is that it permits the transport of high gravel concentrations (up to 15 lbm/gal). HEC gel provided a reasonably clean medium for transporting the gravel-pack sand, the gel allowed consistent batch mixing, and it protected the gravel from crushing and contamination during pumping. Because of its apparent advantages, HEC fluids rapidly replaced brine as the gravel packing fluid of choice. HEC gels remained the "state-of-the-art" gravel transport fluid for many companies until the early 1990s.
Despite the advances in gravel quality, wellbore cleanliness, fluid filtration, and perforation quality, gravel-packed wells were not, in general, producing as efficiently as theoretically possible. Gravel-pack skins from 20 to 100 were common when gels were used. Also, it became common knowledge that gravel packs performed with gelled fluids commonly produced voids in the packs. HEC was evidently not as nondamaging as originally assumed, and as a consequence, improved shear mixing procedures were developed.  Despite better mixing, damage because of residual gel remained likely. Research also indicated that HEC did not pack perforations efficiently in deviated wells with a large interval zone length.  Alternatives to HEC, such as crosslinked (XC) polymers and other special gels, were proposed as the ideal gravel-pack fluid but were never completely accepted.
Research and operating data presented in the early 1990s showed that water was a general-purpose gravel transport fluid that produced low-porosity packs that did not contain voids and was capable of efficiently prepacking perforations, provided that fluid loss was acceptable. Improved mixing equipment was developed for handling brine-sand mixtures in water-pack systems. The equipment allowed consistent mixing of gravel in brine and redirected attention to brine as the gravel transport fluid of choice. Coupled with research data and positive field results, these developments initiated the trend for most of the industry to accept brine as a gravel-pack carrier fluid.  Although gel represented an improvement in technology at the time and is still applicable for certain well situations, brine is the most widely used gravel-pack fluid in the industry today. However, gelled fluids are used extensively for frac packing.
Continued evolution of procedures saw the introduction of DE filtration systems (circa 1980) that were able to filter large quantities of brine quickly at a reasonable cost. Coupled with the increasing use of clear brine, DE filtration systems resulted in substantially cleaner wellbores than previously had been possible.
In 1986, the API introduced specifications for gravel-pack sand (API RP58, Testing Sand Used in Gravel-Packing Techniques) that established rigorous requirements.  The API specifications called for gravel, sieved to strict tolerances with low crush resistance and acid solubility, that was capable of passing through pumping equipment with little or no degradation. Finally, in the early 1980s, underbalanced-tubing-conveyed perforating became a common and well-established technique for achieving the high-shot density, large-hole diameter, clean perforations required for maximum gravel-packed well productivity. All of these improvements, developments, and changes significantly improved the gravel-packing systems that are now offered on a routine service.
Physical Model Observations
Field-scale model studies with water and gelled transport fluids in a 22-ft-long clear plastic gravel-pack model revealed many significant facts concerning gravel placement. The model simulated a 7-in. casing with a 2 3/8-in. screen that had a perforation shot density from 0 to 12 shots/ft. The model could be rotated to simulate well deviations from 0 to 110° from vertical. The following discussion deals primarily with cased-hole completions. It also applies to openhole completions for gravel packing the annulus between the screen and the open hole.
Brine Transport Fluids. Simulations with brine transport fluids were performed at deviations from 0 to 110°. The gravel-packing sequence at well deviations from 0 to 45° were highly controlled by gravity and packed from the bottom of the well upwards, as Fig. 5.26 portrays. As long as finite leakoff occurred through the perforations, they were packed with gravel. The gravel did not begin filling the perforation tunnels until the level of the gravel in the annulus reached the perforation entrance. At this point, the gravel would divert into the perforations (if the perforation was experiencing leakoff) and completely pack the perforation as the annular pack level rose. The result was a tight annular pack that completely prepacked the perforations experiencing leakoff. Well deviations of 45 to 60° from vertical were also completely packed, but the packing began on the low side of the hole and filled the annulus with a series of dunes propagated up and down the length of the model. At about 60° well deviation, the gravel is in transition between falling to the bottom of the interval or remaining at the top of the interval on the low side of the hole. As a consequence, the packing is random, as shown in Fig. 5.27. The reason for this behavior is that at about 60°, it represents the complement of the angle of repose for gravel that is about 28°, as illustrated in Fig. 5.28.
Fig. 5.26—Packing sequence with brine carrier fluids in wells less than 45o.
Fig. 5.27—Packing sequence with brine carrier fluids in wells at 60o.
Fig. 5.28—Angle of repose for gravel-pack sand.
As the well deviation exceeds 60°, a gravel dune forms initially at the top of the completion interval and is propagated sequentially downwards from the top to the bottom of the completion interval. This occurs because the angle of repose has been exceeded, and gravity becomes a more dominant force that causes a gravel dune to form in the completion interval. To ensure propagation of the dune, the ratio of the washpipe OD to the screen ID must be larger than 0.70. The purpose of the large-diameter washpipe is to divert flow from the annulus between the washpipe and the screen to the annulus outside the screen. Testing and field experience has confirmed that the ideal ratio is probably in the range of 0.70 to 0.80. Additionally, the return flow rate to the cross-sectional area ratio (between the screen and the casing) should be at least 1 ft/sec to supply sufficient transport velocity. This is referred to as the superficial velocity. If the ratio of washpipe OD to screen ID is too small, excess fluid will divert into in the annulus between the screen and the washpipe and the gravel dune will stall high in the completion interval, resulting in a "premature sandout" (see Fig. 5.29). Fig. 5.30 shows the effect of washpipe to screen diameter ratios on gravel placement efficiency. If the ratio of washpipe OD to screen ID is too large, sticking the washpipe is a concern, as well as potentially high pump pressures during the final stages of gravel placement. A schematic of the gravel packing process, in wells greater than 60° when a large diameter washpipe is used, is illustrated in Fig. 5.31. This figure shows the dune deposited and propagated along the low side of the hole (sequences 1 to 10) until it reaches the end of the completion interval (alpha wave). At this point a secondary deposition (beta wave) backfills and packs the volume above the alpha wave to complete the gravel pack.
Fig. 5.29—Failed packing sequence with brine carrier fluid in a high-angle well, resulting from a low-rate and small-diameter washpipe.
Fig. 5.30—.Effect of washpipe OD to screen ID ratios on gravel placement efficiency.
Fig. 5.31—Packing sequence with brine carrier fluid in a high-angle well using a high-rate and large-diameter washpipe.
Gel Transport Fluids. Simulations with gel transport fluids were also performed at the same well deviations previously discussed. The packing mechanisms with gel were more complex than with brine because viscous forces were stronger. At 0 to 45°, the high viscosity of the gel allows radial packing around the gravel-pack screen and node buildup at the perforations. At screen connections, voids were commonly observed. But the voids where typically filled by gravel settling after a few hours, provided that the well deviation was less than about 60°. As with brine, perforation packing was complete but occurred only if the perforation experienced fluid leakoff. At deviations greater than 60°, voids persisted in areas where incomplete slurry dehydration occurred (opposite screen joint connections or unperforated sections of the interval). Unlike the lower deviation simulations, gravel pack, settling at deviations greater than 60°, resulted in voids along the top of the gravel pack, as Fig. 5.32 shows. When the voids occurred opposite the perforations, gravel-pack sand placed in the perforations would be unloaded into the voids when production occurred. Under actual conditions, these phenomena result in either sand production or localized filling of the perforation tunnels with formation sand that will severely restrict productivity. Observations were that gravel packing with brine produces a pack with a porosity of about 37%. The porosity of gel packs is about 42% and can be higher if there are voids.
Fig. 5.32—Gravel-pack sequence with viscous fluids showing voids.
Transport Fluid Summary. Based on the results of laboratory testing and field experience, brine exhibits more complete packing of the perforations and annulus under a wide variety of well conditions and is considered by most to be a general-purpose gravel-pack fluid. Gel transport fluids should be limited to use in wells with deviations less than 45° and gross zone lengths less than 50 ft in length.
The main objective of annular gravel placement is to effectively pack the annulus between the screen and the casing or the open hole. For cased-hole completions, an added objective is to pack the perforations with gravel because the latter significantly improves well productivity and longevity. In addition to perforation packing, the quality of the pack in the screen/casing annulus is important, regardless of whether the well is completed cased or openhole. Gravel-pack evaluation logs have demonstrated the superiority of brines over gels in that lower pack porosities are achieved. Brine packs are also more uniform and do not contain voids common with gels that have been verified by post-gravel-pack evaluation logs.
Gravel Packing With Shunts
Because viscous fluids are still used for gravel packing, particularly in frac-pack applications, there is concern about void formation in the annular gravel pack. A shunt system has been developed that may help solve the problems associated with these high-viscosity fluids (voids).  The shunts are actually channels or conduits that are designed to transport gravel through the shunt when bridges are formed in the annulus. Fig. 5.33 is an example of a shunt activating when a bridge forms in the annulus. Note that the shunt (there can be a single or multiple shunt tubes) is attached to the outside of the screen.
The shunt can be run either in cased- or openhole configurations. For cased-hole applications, the shunt screens are usually run unprotected, but in openhole horizontals, an outer shroud is added to protect the shunts when running in the hole. The shroud may also provide centralization for openhole completions. The horizontal shunt-screen gravel packs are commonly performed in the squeeze mode (no returns), and fracturing is believed to be occurring during the packing process. Reports are that when gravel packing with shunt screens up to 35%, excess gravel is pumped over the hole volume. Whether this means that the excess packed washouts occurred because of fracturing is not clear.
The burden of the additional hardware is increased weight, drag, and dimensional concerns; this limits the diameter of the hole in which it can be run. For example, for a 4-in. pipe-base screen, a 7-in. shroud encases the screen and the shunts. Hence, the minimum hole diameter in which the screen assembly can be run is 8.5 in. For smaller diameters such as 6.125 in., which is probably the most common horizontal openhole diameter, a 4.5- to 5-in. shroud would be required. For this shroud diameter, the screen diameter (pipe base) would probably have no more than 2 in.—meaning the washpipe and shunt dimensions are also reduced. Hence, washpipe and shunt friction pressure limit the length of the lateral that can be gravel packed for the small hole sizes.
Prepacking the Perforations
Cased-Hole Gravel Packs
Gravel packing cased-hole completions in vertical and deviated wells are more common than openhole completions, particularly in shaley reservoirs. Reasons for this are several-fold: cased-hole completions are the norm in almost any development because the reservoir is usually easier to manage, so remedial operations are simplified; wellbore stability issues are minimal; and if multiple intervals are involved, openhole completions will not provide the necessary isolation.
However, cased-hole gravel packs have an important requirement that is easily overlooked. The perforations must be prepacked with gravel if productivity and completion longevity is desired.  Not until the late 1980s was the importance of prepacking fully appreciated. The illustration shown in Fig. 5.34 is an example of prepacked perforations. Note that the gravel is packed through each perforation and into the perforation tunnel beyond the cement sheath. Fig. 5.35 shows the benefit of prepacking. This information was taken from large-scale laboratory testing studies that illustrated the pressure drop across perforations filled with 1-darcy formation sand, 20:40 gravel and 20:40, gravel that was prepacked in the perforations.  Tables 5.5 and 5.6 provide additional information. The lowest pressure drop through the perforations occurs when they are prepacked. Lower pressure losses across the perforation not only affect flow from the reservoir, but the larger wellbore pressure provides additional inflow pressure to lift fluids to the surface. Cased-hole gravel packs that have not been prepacked are usually damaged. There is no remedial treatment that can remove the damage (a frac pack can bypass the damage), leading to a well that will be permanently restricted unless a workover is performed to prepack the completions and complete the well properly. Table 5.7 verifies this scenario with field data and shows the superiority of wells that were prepacked.
Fig. 5.35—Effect of perforation packing (0.5-in. perforation on pressure loss).
Prepacking can be defined as any method that intentionally places gravel into the perforation tunnels. Filling of perforation tunnels can be accomplished either with a dedicated operation before performing the gravel pack or simultaneously with it. The technique used is normally dictated by well parameters, such as excessive fluid loss, an extended rathole area, reservoir acid sensitivity, zone length, etc. An additional concern that must be addressed is the question of what transport fluid to use for the prepacking operation. Regardless of the technique selected, to effectively pack the perforations, one critical condition must be met: there must be fluid loss through the perforation. Fig. 5.36 shows the effects of the leakoff rate on the amount of gravel prepacked. Data also show that the well deviation is not a factor on the amount of gravel placed.
Choice of Fluids
Provided that there is leakoff, any fluid can be used. The packing sequences, 1 to 7, when brine and viscous fluids are used, are shown in Figs. 5.37 and 5.38. The two are slightly different because of the viscosity of the fluid. Viscous fluids suspend and transport the gravel completely to the end of the perforation tunnel and then pack back toward the entrance of the perforation. Note the node at the entrance of the perforation caused by viscous forces in Fig. 5.37. With brine, the gravel is initially deposited at the entrance of the perforation, and subsequent packing takes place over the top of the dune until it reaches the end of the perforation. The last volume to be prepacked is that over the dune. The obvious question at this point is which fluid should be used, or which is the best? The question has many operating implications. However, field data from prepacking operations, conducted at matrix rates, show that brines are superior because they pack more gravel.
Fig. 5.37—Perforation with viscous transport fluid.
Fig. 5.38—Perforation filling with brine transport fluid.
Prepacking Below Fracture Pressure
To prepack below fracture pressure, the perforations must be clean and contain no debris. There must be leakoff into the formation. A void outside the perforation is desirable.
Viscous Gravel Packs.
These completions consist of gravel packing with viscous gels—slurry packs in which there is no dedicated procedure to prepack the perforations. Any prepacking that occurs is simultaneous with the gravel pack. Example field results using this approach (Fig. 5.39a) for a project in southeast Asia reflect the performance in terms of the skin factors measured after completion.  Some wells performed exceptionally well (i.e., the skin factor was small), while others were disappointing. Completion success was inconsistent. The average of the data indicated a skin factor of about 24 or a flow efficiency of 25%, which is common for gel packs. Whether the problem with well performance was a lack of prepacking or damage caused by other factors is not known. Acidizing is probably the only alternative for restoring production for this example, but it will never restore reservoir capacity if the perforations are not prepacked.
Fig. 5.39a—Distribution of gel-pack skins.
Acid Prepacking. Acid prepacking has been used to improve productivity. A critical aspect of a successful damage removal procedure is that the acid must come into contact with the entire interval. In addition, it has been commonly thought that contact time must be sufficient to allow all of the damage to be dissolved. With these assumptions, during the mid-1980s, acid prepacking quickly evolved into a process in which a diverted acid treatment was pumped at a low rate. Several studies indicated that one of the most effective diverters for acid prepacking is to carry relatively small quantities of sand in an HEC gel. While this combination did provide good diversion, the well test results, shown in Fig. 5.39b, tended to be inconsistent. Poor perforation filling from injecting a sand/gel slurry into the perforations at a low rate, coupled with formation damage, resulting from the use of HEC, are the most likely causes for the elevated skins. The detrimental effects of questionable perforation filling can easily overpower any benefit obtained from using the acid.
Fig. 5.39b—Distribution of conventional acid prepack skins.
Dedicated Prepack Operations. High matrix injection rates and the use of nonviscous transport fluids are two techniques that have been demonstrated to improve perforation filling. The traditional acid prepacking techniques violate both of these conditions. If the perforation filling is indeed critical for cased-hole gravel packs, completion methods that focus on filling perforations should prove superior to those that sacrifice perforation filling for damage removal. Fig. 5.40 illustrates this point. Here the skin factors from 55 Gulf of Mexico wells are shown, 42 of which were prepacked at matrix rates with a 20 lbm/1,000 gal HEC (slickwater) fluid. Typical prepack volumes were about 40 lbm/ft. An annular brine gravel pack followed prepacking. The remaining wells were completed with a water prepack and an annular brine pack. The wells completed with the gel prepack required post-gravel-pack acid to achieve the performance reported in Fig. 5.40. However, the transport fluid was able to easily leak off to the formation, and high injection rates were used to enhance placement of gravel in the perforation tunnels. The data presented indicate that not only are the average skin factors reduced compared to slurry packing and acid prepacking (Figs. 5.39b and 5.40), but the overall consistency was also improved (especially for high-permeability thick formations). These data demonstrate that when prepacking below fracture pressure, it is more important to ensure that as many perforations as possible are completely filled with gravel-pack sand than for the damage to be removed. However, it must be remembered that improved well performance will result if damage can be effectively removed without jeopardizing the filling of the perforations.
Fig. 5.40—Distribution of dedicated brine-pack skins.
Prepacking Above Fracture Pressure
One of the main detriments to prepacking below fracture pressure is that gravel can only be placed into voids created during underbalanced perforating or perforation cleanup. If the amount of penetration into the formation does not extend completely through the near-wellbore damaged zone, restricted well productivity results. To overcome this difficulty, it becomes necessary to remove the damage with acid. This is not always easily accomplished if sufficient gravel has not been prepacked. Another technique to eliminate the effects of the damaged zone is to bypass it rather than to attempt to remove it. This is accomplished by hydraulically inducing a fracture in which the orientation is normal to the least principal stress in the formation.
Techniques available to create these fractures include brine fracturing or a frac pack. To allow frac packing and water fracs to be distinguished, a description of these techniques is discussed next.
Frac Pack. A fracture with a length of about 100 ft can be created with a viscous transport fluid, but typical lengths are usually shorter. High pump rates are typically used (15 to 20 bbl/min), with proppant concentration increasing from 12 to 15 lbm/gal. The total amount of gravel pumped is typically in excess of 1,000 lbm/ft. Horsepower requirements may exceed 5,000 hydraulic horsepower (hhp) but are commonly lower.
Water Frac. A fracture with a length between 5 and 15 ft can be created with a low-viscosity (brine) transport fluid. Pump rates are higher than for conventional gravel packing but usually lower than a frac pack. Typical pump rates are in the range of 8 to 12 bbl/min. Proppant loading is held constant between 1 and 2 lbm/gal, and total job size is typically from 100 to 150 lbm/ft. These treatments can be multistaged to further enhance the ability to effectively treat several sand subintervals with a single treatment. Horsepower requirements are typically about 1,000 hhp.
Treatment Comparison. From the description of these prepacking treatments, frac packs are significantly larger than water fracs. The frac packs appear to reach much farther out in the reservoir as a consequence of the longer fracture lengths, while the water fracs focus is near the wellbore. The amount of fracture length required is a question that arises. Many propose that bigger is better. 
When water is used as the fracturing fluid, short, narrow fractures are created because of the fluid's low viscosity that results in a hydraulic fluid efficiency less than 5%. With frac packs, the fluid efficiency is in the range of about 25% because viscosified fluids reduce leakoff. Also, frac packs are designed for a tip screenout that ceases fracture length extension before the end of the treatment. Continued pumping with high gravel concentrations is intended to increase the width of the fracture to increase fracture conductivity.
The gravel placement geometry in a water-frac treatment forms an equilibrium gravel bank similar to that shown in Fig. 5.41. Frac packs pumped in viscous fluids at high gravel concentrations also probably have a small equilibrium gravel bank, but substantially more of the gravel tends to be suspended in the fracture at higher concentrations, which provides for the wide fractures after closure.
Both treatments can be pumped in either a single step or two steps. In the single-step approach, the formation is fractured and subsequently gravel packed in one pumping sequence. In the two-step method, the fracturing and the annular gravel are performed separately. Of the two alternatives, the single-step method is preferred because it is less expensive and time consuming.
There are proponents of both fracture prepacking methods. Some prefer the frac packs because they believe that the longer, wider fractures provide less risk of a low-productivity well. Proponents of water fracs cite lower costs and operations conducted with platform-based equipment as advantages. From the standpoint of productivity improvement (stimulation) in the high-permeability wells, long fractures are not required, and fracture conductivity is more significant than length, provided the fracture extends past the damage.
Probably the best way to compare the benefits of the various prepack treatments is to compare their relative performance based on experience in the field. Figs. 5.42 and 5.43 compare frac packs and water fracs. Because there is a wide discrepancy in their designs and fracture geometry, one might think that the frac packs with long, wide fractures would provide a superior result. While there are similarities between the techniques, comparing the results of the frac packs to the water fracs reveals that the skin distributions are almost identical. These data strongly suggest that the main benefit of either treatment is perforation prepacking and damage bypass, regardless of which prepack technique is implemented. Credence to this viewpoint is that neither of the fracture prepack methods produces completions with large negative skin factors that have been achieved with conventional fracturing in consolidated formations. Skin factors below –1 are rare for any cased-hole gravel pack.
Openhole Gravel Packing
Openhole completions provide another opportunity for sand control. Many engineers do not routinely think of performing an openhole completion when confronted with selecting a completion. This is true probably because cased-hole completions are so widely accepted and because they are not familiar with selection criteria and procedures. However, openhole completions provide excellent, high-productivity completions, but they must be applied under the right reservoir conditions. They avoid the difficulties and concerns of perforation packing and reduce the gravel-placement operations to the relatively simple task of packing the screen/openhole annulus. Because openhole gravel packs have no perforation tunnels, formation fluids can converge toward and through the gravel pack radically from 360°, eliminating the high pressure drop associated with linear flow through perforation tunnels. The reduced pressure drop through an openhole gravel pack virtually guarantees that it will be more productive than a cased-hole gravel pack in the same formation, provided they are executed properly. Fig. 5.44 illustrates the theoretical pressure drops experienced in openhole and cased-hole gravel packs. It reveals that openhole gravel packs result in virtually no additional pressure drop as the formation fluids converge at the wellbore.
Fig. 5.44—Comparison of pressure drawdowns for cased- and openhole gravel packs.
Guidelines for Selecting Openhole Gravel-Pack Candidates
Despite their potential for creating high-productivity wells, openhole gravel packs are not suitable for all reservoirs and formations. One disadvantage of the openhole completion (including openhole gravel packs) is the inability to always isolate unwanted water and/or gas production. Unlike cased-hole completions that can be precisely and selectively perforated in the zones of interest, openhole completions sometimes offer less control over fluids (water, oil, and gas) exposed to the wellbore. Furthermore, remedial operations (such as squeeze cementing, plugbacks, or straddle packoffs) to isolate unwanted fluid production can be carried out with a reasonably good chance of success with little to no planning in a cased-hole well. Such remedial operations in an openhole well (with the exception of a plugback) require additional planning to isolate undesirable fluids. With this in mind, openhole completions are best suited for thick reservoir sands rather than multiple sand reservoirs where there is water and/or gas to contend with.
Maintaining borehole stability during drilling and completion is an essential requirement for openhole gravel packs. Concern over the lack of borehole stability is a primary reason that openhole gravel packs are not used more often in unconsolidated, dilatant formations. Unstable boreholes make running of the gravel-pack assembly difficult and may prevent proper gravel placement if the formation flows in around the screen. Fortunately, state-of-the-art drill-in fluids are usually effective in maintaining borehole stability while performing a horizontal completion in dilatant-type formations.
Openhole gravel packs should be avoided in formations with several sand and shale laminations if the shales are prone to uncontrollable eroding and/or sloughing. During gravel placement, the shale can intermix with the gravel-pack sand, resulting in reduced gravel permeability and impaired well performance. Again, proper drill-in fluid selection can alleviate some of the problems associated with laminated sand and shale formations. The guidelines for selecting openhole gravel-pack candidates are listed next.
- Formations where cased-hole gravel packing has unacceptable productivity.
- Wells where increased productivity is required.
- Reservoirs where long, sustained single-phase hydrocarbon flow is anticipated.
- Situations where workovers for isolating gas or water cannot be accomplished.
- Wells where high water/oil or gas/oil ratios can be tolerated.
- Reservoirs with single uniform sands (avoid multiple sands interspersed with troublesome shale layers or water sands).
- Formations that can be drilled and completed maintaining borehole stability in the completion interval.
- Wells where cased-hole completions are significantly more expensive (i.e., long horizontal wells).
Top-Set Openhole Gravel Pack
The most common type of openhole completion is referred to as "top set," which is illustrated in Fig. 5.45. While this figure shows a vertical completion, this discussion is also pertinent to openhole horizontal wells. In this completion, the production casing is set at the top of the completion interval to isolate overlying strata. Once the casing is cemented, the productive formation is drilled to total depth; the hole is cleaned and displaced; and the gravel pack is installed. Critical issues in top-set openhole gravel packs include: selecting the casing seat, drilling the open hole, underreaming if necessary, and cleaning the hole and gravel packing. See the chapter on completion design in this section of the Handbook.
Selecting the Casing Seat
Selecting the casing seat at the proper depth can have a significant impact on the success and cost of an openhole completion. Normally, the casing should be set at the top of the reservoir, just barely into the productive interval. If the overlying formation is an unstable or sloughing (heaving) shale, failure to isolate the shale behind casing may cause problems and delays throughout the remainder of the completion. Well logs should be run to ensure that all offending strata have been penetrated and will be cased before running the casing. In some instances, several logging runs may be required as the well is deepened to determine exactly when the casing should be run. In the case of logging while drilling, the casing point can be easily picked without multiple logging runs. Alternatively, the well can be drilled to total depth and logged to determine the appropriate casing depth. Then a sand plug can be placed across the productive interval before cementing the casing.
Drilling the Open Hole
Several options are available for drilling the openhole completion interval. How this is performed and the type of fluids used depend on the mineral and fluid content of the formation (i.e., whether it is sensitive to the drilling and/or completion fluid). Another factor is whether to enlarge the hole by underreaming. The fluid used for drilling the open hole is critical to the success of the completion. The general requirements of an ideal drill-in (or underreaming) fluid, which apply to any openhole completion and are not specific to gravel packs, are compatibility with the reservoir rock and fluids (nondamaging); good suspension properties; low friction loss; low fluid loss; easily controlled density; ready availability; low cost; ease of mixing and handling; nontoxicity; and thin friable filter cakes with low breakout pressure.
While most fluids do not have all of these properties, some, such as calcium carbonate brine fluids, have performed well as drill-in and underreaming fluids. The critical issue is that the drill-in fluid should do minimal irreversible damage to the face of the formation. The solid-laden fluids should quickly form a filter cake to minimize filtrate losses. The filter cake should be easily removable before or after gravel packing. The ease with which it is removed is reflected in a low breakout pressure. Breakout pressure is reached when drawdown pressure, required to initiate production after the formation, has been mudded off with the drill-in fluid. In rare cases, clear brines have been acceptable as nondamaging drill-in fluids. If the open hole is to be underreamed, standard drilling mud may be used as a drill-in fluid, provided that the underreaming operation, using calcium carbonate brine-based systems, removes the mud-invaded, damaged portion of the formation.
Underreaming is the operation of enlarging the hole size below the casing shoe. One reason for underreaming an open hole is to remove damage present in the pilot hole. Underreaming may be unnecessary if the pilot hole is drilled with a nondamaging fluid. The larger-diameter hole also enhances the well productivity slightly, but in most cases, this is insignificant. Underreaming may be performed simply to provide greater clearance between the screen and the open hole. In any event, underreaming should be performed with a nondamaging fluid that keeps the hole stable. Traditional drilling muds should be used only as a last alternative, and damage-removal treatments should be planned before placing the well on production if these muds are used.
Underreaming is usually more of an annoyance than an incremental time, cost, or productivity issue because a cased-hole completion also requires changing over to a clean fluid before perforating. Perforating, of course, is unnecessary. Underreaming and perforating usually offset each other in incremental costs.
In the event that running a liner across the completion interval at a later date is an option to isolate unwanted fluids, underreaming probably should be avoided. The cement sheath in an underreamed hole will be much thicker than normal and will interfere with effective perforating or make perforating operations more difficult. The difficulties are that perforating, or ineffective perforations, will adversely affect gravel packing and, subsequently, will restrict well productivity.
Solids can be drill-in fluids, drill solids, and gravel-pack sand. The importance of cleaning the hole and the filter cake is shown in Fig. 5.46. This bar graph is based on field data collected from 10 wells and shows the relationship between completion skin and hole cleaning. This relationship is not too surprising, but what is often overlooked is that once a well is damaged, subsequent acid treatments increase productivity but will not yield an undamaged well. Before running the screen in the hole and gravel packing, it is necessary to remove the drill-in fluid, drill solids from the hole, clean the hole, and scour the filter cake to its dynamic thinness.
Set-Through Openhole Gravel Pack
When accurately setting the casing depth is difficult or secondary pay zones exist above the primary target, set-though openhole completions can be applied. In this type of completion, the casing is run through all formation pay zones and cemented in place. Cased- and openhole well logs are used to determine the exact location of the pay zones behind the casing, and windows are milled (with a nondamaging fluid) opposite the completion interval to create an "openhole" environment. The well can then be gravel packed. Schematics of example set-through-type completions are shown in Fig. 5.47. Because of the amount of debris created by milling casing windows, it is recommended that all set-through openhole completions be underreamed to expose a clean, nondamaged formation face. A requirement in applying set-through-type completions is a good cement job. The casing must be securely cemented to facilitate milling operations and maintain alignment between the upper casing and the lower casing sections. Because a sump packer can be used, a set-through gravel pack assembly is basically the same as a cased-hole type. The only exception would be the use of bow-spring-type centralizers in long openhole sections. Set-through-type completions are especially well suited for recompletions in existing wells.
Gravel Packing Openhole Completions
To gravel pack an openhole completion, follow the well preparation and gravel placement guidelines previously discussed.
Sand Control in Horizontal and Long-Throw Highly-Deviated Wells
Horizontal well completions have been attempted in a myriad of reservoir situations to increase well productivity, improve reservoir management, and access incremental reserves that could not be developed economically with vertical wells. While the first horizontal wells were drilled in competent formations, eventually soft formations were completed horizontally. Practically all horizontal wells drilled in soft formations have been completed openhole. Most of these boreholes did not collapse; however, because many of these completions were in formations, where conventional sand-control applications were practiced, slotted liners and wire-wrapped or prepacked screens were run to prevent hole collapse and sand production because horizontal gravel-pack technology was not yet available.
Stand-Alone Slotted Linear and Screen Completions
The typical procedure for completing horizontal wells with slotted liners and screens is to drill the well to the casing seat, set casing, drill the horizontal section, displace the hole, run the screen, and then produce the well. It is not always this simple, but the intent should be to follow these guidelines.
Sand-control horizontal wells were originally dealt with by using stand-alone slotted liners, screens, and, more recently, proprietary screens. The initial productivity of these completions was usually acceptable, and some were outstanding; however, in most applications, the stand-alone devices either plugged or cut out (eroded) with time. The consequences are either unacceptably low well rates or excessive sand production. The acknowledged stand-alone screen failure rate in the Gulf of Mexico was estimated to be about 25% in 1996. Since that time, numerous additional failures have occurred, and the failure rate has increased substantially. Hence, in most applications, the use of stand-alone screens as retention devices has been disappointing because the stand-alone screen approach forces them to perform as filters (see Fig. 5.48). Their use in horizontals confirmed previous stand-alone experience in vertical wells—they plugged. Many screen designs were progressively used to determine if particular designs would improve performance: slotted liners, wire-wrapped screens, prepacked screens, and the high inflow-area proprietary screens. As might be expected, these completions experienced a wide range of reservoir situations. Some stand-alone applications have performed exceptionally well. The exceptional wells (mainly in the North Sea) had formation permeabilities in the range of 10 to 12 darcy and were well sorted. Experience in the Gulf of Mexico with stand-alone screen completions has been disappointing; the failure rate from these completions has been well over 70% as of 2000.
In many horizontal wells where stand-alone screens have been used, there are implications that the formation does not collapse around the screen. When this happens, there is an open annulus that serves as a conduit for fluid and particulate transport along the entire length of the screen. There are many examples in which a stand-alone screen completion produced extremely well for a period of time and, then, abruptly lost productivity. The screens appear to be progressively plugging; however, because of the high flow capacity per foot of screen, a short section of unplugged screen can handle enormous flow rates. When the last few increments of screen plug, either production ceases or the screen erodes. Fig. 5.49 displays an example.
Fig. 5.49—Schematic of prepack screen plugging.
To combat these problems, technology has been developed to gravel pack horizontal wells because gravel packing can sustain productivity. Gravel packing has always been the state-of-the-art technology for vertical wells. Gravel-pack technology was not available for horizontal wells until 1995, but its acceptance has been steadily increasing and is now the preferred technique. In this service, the screen functions as a gravel-retention device, and the gravel placed around the screen fills and stabilizes the borehole. The streamlines into the screen are now normal because the annulus between the screen and the open hole is filled with gravel, as Fig. 5.50 suggests. The result is sustained productivity.
Horizontal Gravel Packing
Gravel packing offers another option for completing a horizontal well when sand production represents a problem. The original perception was that technology was not available for gravel packing long, horizontal completions, and other alternatives, such as stand-alone screens, had to suffice. This is contrary to the fact that the performance of stand-alone screens had been unacceptable in conventional wells. One of the most disturbing examples, portrayed in Table 5.8, shows failure statistics and average pressure drops across 43 stand-alone screen completions in horizontal wells in the Gulf of Mexico. Of these, 15 (35%) were classified as failures, but the remaining active wells are producing at an average pressure drop of 545 psi. Taken from the perspective of the flow capacities of screens that were previously discussed, the remaining wells, while still producing and not reported as failures, are also plugged.
Horizontal gravel-pack technology was developed in the mid-1990s. Studies were performed in a field-scale model that was 1,500 ft long and instrumented with data acquisition; they also contained visual observations of the packing process through high-strength plastic sections in the model. A typical plot of the location of the alpha and beta waves (see the section on gravel placement techniques), as a function of time for a horizontal gravel pack, is illustrated in Fig. 5.51. The figure demonstrates that the entire 1,500-ft model was packed with gravel. Testing clearly revealed that the height of the alpha wave was not constant with pack length, as had been implied from studies conducted in short models. Instead, the height of the alpha wave was inclined upward from the heel to the toe of the model as Fig. 5.52 illustrates. The reason for the inclination is a result of fluid loss that reduces the annular flow velocity and increases the gravel concentration, thereby reducing the gravel transport efficiency. The consequence was an increase in the alpha-wave dune height with length. Having this data provided valuable information for designing horizontal gravel packs. If the top of the borehole interferes with deposition over the top of the alpha wave, deposition stalls, and beta-wave deposition begins at the stall location (Fig. 5.53). To avoid a premature stall, the superficial annular velocity must be maintained above 1 ft/sec, based on return flow through the washpipe. The superficial velocity is defined as the ratio of the return flow rate through the washpipe to the annular area between the washpipe and the wellbore. Provided that the design of the gravel pack is correct and a superficial velocity of 1 ft/sec is maintained, gravel packing a long horizontal gravel pack can be performed with routine procedures. Gravel deposition (alpha-beta wave) will proceed to the toe of the well, as Fig. 5.54 shows.
Fig. 5.51—Gravel dune location (alpha-beta wave).
Fig. 5.52—Dune height in a wellbore.
Fig. 5.53—Horizontal gravel pack (partial).
Fig. 5.54—Horizontal gravel pack (complete pack).
Horizontal gravel designs are available that utilize the concept illustrated in Fig. 5.55, which shows pressure plotted as a function of pump rate. The fracture pressure is identified, and a treating pressure is shown. Note that at low rates, there is insufficient transport to initiate alpha-wave transport, but at slightly higher pump rates, the alpha wave will prematurely stall. However, at an acceptable pump rate, the entire alpha-beta wave deposition can be performed to complete the gravel pack without fracturing the formation. Fracturing is manifest by a reduction in return through the wash pump and will stall the transport process.
Fig. 5.55—Horizontal gravel-pack design criteria.
As of the year 2001, over 400 horizontal gravel packs have been performed. Most of these completions had horizontal lengths of 1,500 to 2,000 ft. The longest horizontal gravel pack performed as of mid-2001 has been 7,000 ft. The volume of gravel pack in these completions is typically 20 to 30% greater than the theoretical volume, indicating that the annulus is completely filled with gravel. The pack volume being greater than 100% is accounted for by hole irregularities that are larger than the bit diameter. Similar experience has been noted in vertical openhole gravel packs. In several applications of this technology, gravel packs were run behind failed stand-alone screen completions that lost productivity. After the screen was removed and the hole was displaced, new equipment was run, and the well was gravel packed. The performance of the horizontal gravel packs has demonstrated that they maintain productivity compared to the stand-alone screen experience.
|Cμ||=||sorting factor or uniformity coefficient|
|d40||=||formation sand diameter, 40 percentile|
|d50||=||formation sand diameter, 50 percentile|
|d90||=||formation sand diameter, 90 percentile|
|d||=||formation sand diameter|
|D50||=||median grain size of the gravel-pack sand|
|Rex||=||removal efficiency for particle size "x" (percent)|
|β||=||beta ratio for particle size "x"|
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SI Metric Conversion Factors
|bbl/min||×||2.649 788||E–03||=||m3 s–1|
|°F||(F – 32)/1.8||=||°C|
|in.||×||2.54*||E + 00||=||cm|
|psi||×||6.894 757||E + 00||=||kPa|
*Conversion factor is exact.