Sand control

From OilfieldWiki
Jump to: navigation, search
Sand control refers to managing/minimizing sand and fine production during petroleum production. An illustration of sand control by screen with gravel pack[1].
Sand accumulation in a separator, which decreases fluid resident time and causes poor separator performance.

Sand control refers to managing/minimizing sand and fine production during petroleum production. Sand and fine produced with oil and gas can cause erosion and wear of production facilities/equipments, resulting in production downtime, expensive repairs, and potentially loss of containment (serious safety risk).



For normal flow of oil, formation should be porous, permeable and well cemented together, so that the large volumes of hydrocarbons can flow easily through the formations and into production wells.

There are few situations arises where these produced fluids may carry entrained there in sand. Unconsolidated sandstone reservoirs with permeability of 0.5 to 8 Darcie’s are most susceptible to sand production. This may start during first flow or later when reservoir pressure has fallen or water breaks through. Sand production strikes with varying degrees of severity, not all of which require action. The rate of sand production may decline with time at constant production conditions and is frequently associated with cleanup after stimulation.

Sometimes, even continuous sand production is tolerated. But this option may lead to a well becoming seriously damaged, production being killed or surface equipment being disabled. What constitutes an acceptable level of sand production depends on operational constraints like resistance to erosion, separator capacity, ease of sand disposal and the capability of artificial lift equipment to remove sand laden fluid from the well.

Sand entering production wells is one of the oldest problems faced by oil companies and one of the toughest to solve. Production of sand during oil production causes severe operational problem for oil producers. Every year the petroleum industry spends millions of dollars in sand cleaning, repair problems related to sand production and lost problems related to sand production and lost revenues due to restricted production rates.

Consequently, sand control has been a research topic for over five decades. The purpose of this document is to help in understanding the causes of sanding, and how it can be predicted and controlled. It will examine the main methods of sand control.

Reasons for sand production

The solid material produced from a well can consist of both formation fines and load bearing solids. The production of fines cannot normally be prevented and is actually beneficial. The critical factor to assessing the risk of sand production from a particular well is whether or not the production of load bearing particles can be maintained below an acceptable level at the anticipated flow rates and producing conditions which will make the well production acceptable.

The following list summarizes many of the factors that influence the tendency of a well to produce sand:

  • Degree of consolidation: A mechanical characteristic of rock that is related to the degree of consolidation is called “compressive strength”. This shows how strong the individual sand grains are bound together. The cementation is typically a secondary geological process for consolidation. Poorly consolidated sandstone formations usually have a compressive strength that is less than 1,000 pounds per square inch. This indicates that sand production is normally a problem when producing from poorly consolidated sandstone.
  • Production rate: The production of reservoir fluids creates pressure differential and frictional drag forces that can combine to exceed the formation compressive strength. This indicates that there is a critical flow rate for most wells below which pressure differential and frictional drag forces are not great enough to exceed the formation compressive strength and cause sand production. The critical flow rate of a well may be determined by slowly increasing the production rate until sand production is detected. One technique used to minimize the production of sand is to choke the flow rate down to the critical flow rate where sand production does not occur or has an acceptable level.
  • Drawdown: An arch is a hemispherical cap of interlocking sand grains (below figure show the arch) like the stones in an arched doorway that is stable at constant drawdown and flow rate, preventing sand movement. Changes in flow rate or production shut-in may result in collapse of the arch, causing sand to be produced until a new arch forms.
A stable arch is believed to form around the entrance to a perforation cavity. This arch remains stable as long as flow rate and drawdonw are constant. If these are altered, the arch collapses and a new one formas once flow stabilizes again.
  • Reduction of Pore Pressure: The pressure in the reservoir supports some of the weight of the overlying rock. As the reservoir pressure is depleted throughout the producing life of a well, some of the support for the overlying rock is removed. Lowering the reservoir pressure creates an increasing amount of stress on the formation sand itself. At some point the formation sand grains may break loose from the matrix, or may be crushed, creating fines that are produced along with the well fluids. Compaction of the reservoir rock due to a reduction in pore pressure can result in surface subsidence.
  • Reservoir Fluid Viscosity: The frictional drag force exerted on the formation sand grains is created by the flow of reservoir fluid. This frictional drag force is directly related to the velocity of fluid flow and the viscosity of the reservoir fluid being produced. High reservoir fluid viscosity will apply a greater frictional drag force to the formation sand grains than will a reservoir fluid with a low viscosity. The influence of viscous drag causes sand to be produced from heavy oil reservoirs, which contain low gravity, high viscosity oils even at low flow velocities.
  • Increasing Water Production: Sand production may increase or begin as water begins to be produced or as water cut increases. Two possibilities may explain many of these occurrences. First, for a typical water-wet sandstone formation, some grain-to-grain cohesiveness is provided by the surface tension of the connate water surrounding each sand grain. At the onset of water production, the connate water tends to cohere to the produced water, resulting in a reduction of the surface tension forces and subsequent reduction in the grain-to-grain cohesiveness. Water production has been shown to severely limit the stability of the sand arch around a perforation resulting in the initiation of sand production. A second mechanism by which water production affects sand production is related to the effects of relative permeability. As the water cut increases, the relative permeability to oil decreases.

These results in an increasing pressure differential being required to produce oil at the same rate. An increase in pressure differential near the wellbore creates a greater shear force across the formation sand grains. Once again, the higher stresses can lead to instability of the sand arch around each perforation and subsequent sand production

Problems with sand flow

The effects of sand production are nearly always detrimental to the short and/or long term productivity of the well. Although some wells routinely experience “manageable” sand production, these wells are the exception.

  • Accumulation in Surface Equipment: If the production velocity is great enough to carry sand up the tubing, the sand may become trapped in the separator, HE, or production pipeline. If a large enough volume of 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 clean out cost, the cost of the deferred production must be considered.
  • Accumulation Down hole: If the production velocity is not great enough to carry sand to the surface, the sand may bridge off in the tubing or fall and begin to fill the inside of the casing. Eventually, the producing interval may be completely covered with sand. In either 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 production.

One clean-out technique is to run a "bailer" on the end of slick line to remove the sand from the production tubing or casing. Since the bailer removes only a small volume of sand at a time, multiple slick line runs are necessary to clean out the well. Another clean-out 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.

  • Erosion of Down hole and Surface Equipment: In highly productive wells, fluids flowing at high velocity and carrying sand can produce excessive erosion of both down hole and surface equipment leading to frequent maintenance to replace the damaged equipment. If the erosion is severe or occurs over a sufficient length of time, complete failure of surface and/or down hole equipment may occur, resulting in critical safety and environmental problems[2].
The picture shows Sand choking in separator, Pipe line failure, Erosion of equipment and Downhole failure.
  • Collapse of the Formation: Large volumes of sand may be carried out of the formation with produced fluid. If the rate of sand production is great enough and continues for a sufficient period of time, an empty area or void will develop behind the casing that will continue to grow larger as more sand is produced. When the void becomes large enough, the overlying shale or formation sand above the void may collapse into the void due to a lack of material to provide support.

When this collapse occurs, the sand grains rearrange themselves to create a lower permeability than originally existed. This will be especially true for formation sand with a high clay content or wide range of grain sizes. For formation sand with a narrow grain size distribution and/or very little clay, the rearrangement of formation sand will cause a change in permeability that may be less obvious. In the case of overlying shale collapsing, complete loss of productivity is probable. In most cases, continued long term production of formation sand will usually decrease the well’s productivity and ultimate recovery.

  • Sand handling: Sand handling and disposing also possess major problem especially in the offshore installations because Disposal of produced sands is costly.

Predicting sanding potential

Methods for predicting sanding rates include field observations, laboratory experiments, and theoretical models (correlations).

Field observations

The completion engineer needs to know the conditions under which a well will produce sand. This is not always a straightforward task. At its simplest, sand prediction involves observing the performance of nearby offset wells.

In exploratory wells, a sand flow test is often used to assess the formation stability. A sand flow test involves sand production being detected and measured on surface during a drill stem test (DST). Quantitative information may be acquired by gradually increasing flow rate until sand is produced, the anticipated flow capacity of the completion is reached or the maximum drawdown is achieved.

Field techniques like micro fracturing allow measurement of some far-field earth stresses (see “Cracking Rock: Progress in Fracture Treatment Design). Down-hole wire-line log measurements provide continuous profiles of data. However, no logging tool yields a direct measurement of rock strength or in-situ stress.

Formation Strength Log

The general procedure followed by most operators considering whether or not sand control is required, is to determine the hardness of the formation rock (i.e., the rock’s compressive strength). Since the rock’s compressive strength has the same units as the pressure drawdown in the reservoir, the two parameters can be compared on a one to one basis and drawdown limits for specific wells can be determined. Research performed in the early 1970’s shows that there is a relationship between the compressive strength and the incidence of rock failure. These studies show that the rock failed and began to produce sand when the drawdown pressure is 1.7 times the compressive strength.

Sonic Log

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 in microseconds. The porosity is related to the sonic travel time. Short travel times, (for example, 50 microseconds) are indicative of low porosity and hard, dense rock; while long travel times (for example, 95 microseconds or higher) are associated with softer, lower density, higher porosity rock. A common technique used for determining if sand control is required in a given geologic area is to correlate incidences of sand production with the sonic log readings. This establishes a quick and basic approach to the need for sand control, but the technique can be unreliable and is not strictly applicable in geologic areas other than the one in which it was developed.

Formation Properties Log

Certain well logs such as the sonic (as discussed above), density and neutron devices are indicators of porosity and formation hardness. For a particular formation, a low density reading is indicative of a high porosity. The neutron logs are primarily an indicator of porosity. Calculations using the results of the sonic, density, and neutron logs to determine the likelihood of whether a formation will or will not produce formation material at certain levels of pressure drawdown. This calculation identifies which intervals are stronger and which are weaker and more prone to produce formation material.

Laboratory Experiments

Experiments on recovered cores may be used to gather rock strength data. This information may then be used to predict the drawdown pressure that will induce sanding zones of some of the wells.

Theoretical models

A correlation may then be established between sand production, well data, and field and operational parameters. Accurately predicting sand production potential requires detailed knowledge of the formation’s mechanical strength, the in-situ earth stresses and the way the rock will fail.

Finite Element Analysis Model: Probably the most sophisticated approach to predicting sand production is the use of geo mechanical numerical models developed to analyze fluid flow through the reservoir in relation to the formation strength. The effects of formation stress associated with fluid flow in the immediate region around the wellbore are 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 both in the elastic and plastic regions where the formation begins to fail. Both of these input data are difficult to determine with a high degree of accuracy under actual downhole conditions and that 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. Recently developed models “IMPACT”-Integrated Mechanical Properties Analysis & Characterization of Near Wellbore Heterogeneity, developed by Schlumberger and "Geo Mechanical International (GMI)" by Baker Hughes are mostly helpful for superior and production predictions. (Website list provided in reference for model predictions).

Control methods

Sand control methods may be classified as mechanical and chemical. Mechanical methods of sand control prevent sand production by stopping the formation with liners, screens or gravel packs. Larger formation sand grains are stopped, and they in turn stop smaller formation sand grains. Chemical control methods involve in injecting consolidating materials like resins into the formation to cement the sand grains. Here we are discussing the most important control measures which are in practice.

Resin Injection

This is simply considered as artificial consolidation of sand. Which Involves injection of plastic resins, which are attracted to the formation sand grains. The resin 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. Three types of resins are commercially available: epoxies, furans (including furan/phenolic blends), and pure phenolic. The resins are in a liquid form when they enter the formation and a catalyst or curing agent is required for hardening. Some systems use “internal” catalysts that are mixed into the resin solution at the surface and require time and/or temperature to harden the resin.

Resin application in perforation
Properties of resins:
  • Viscosity of resin not excessive.
  • Resin must wet the formation solids
  • Resin possess sufficient tensile and compressive strength
  • Polymerization time must be controlled
  • Final polymer must be chemically inert
  • Pre flush diesel oil which creates wettability and remove undesired material in the zone
  • Placement of resin by isolating the interval
  • Over flush of high concentrated resin injected to control the permeability and compressive strength
  • Leaves wellbore open
  • Relatively low cost
  • Eliminates necessity for screens and liners
  • Limited zone height
  • Longevity limited
  • Temperature sensitivity <250°F
  • Very difficult to evenly apply
  • Reduces permeability by10%-60%

Applied in Gulf Coast with 80% success rate where 50% of permeability retained and compressive strength ranged from 3000±12000 psi.This method represents only 10% of overall sand treatment methods used. Main purpose is to increase formation strength and maintain permeability at the same time Cheap but comes with many disadvantages compared to other methods.

Screen with Gravel Pack

Gravel pack has been used in industry since 1930s; today it’s the most widely used on sand control treatment. Gravel packing account for three quarters of the sand control treatments.

Gravel packing relies on the bridging of formation sand against larger sand with the larger sand positively retained by a slotted liner or screen. The larger sand (referred to as gravel pack sand or simply, gravel) is sized to be about 5 to 6 times larger than the formation sand. Gravel packing creates a permeable downhole filter that will allow the production of the formation fluids but restrict the entry and production of formation sand. Schematics of an open hole and cased hole gravel pack are shown in Figure. Because 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 packs are performed by running the slotted liner or screen in the hole and circulating the gravel into position using a carrier fluid. For optimum results, all the space between the screen and formation must be completely packed with high permeability gravel pack sand. Complete packing is relatively simple in open hole completions, but can be challenging in cased hole perforated completions. Although expensive, gravel packs have proven to be the most reliable sand control technique available and are, therefore, the most common approach used.

Gravelpacking in open and cased holes (1)
Gravelpacking in open and cased holes (2)
Gravelpacking in open and cased holes (3)

A summary of the advantages and disadvantages of open hole gravel pack as well as the guidelines for selecting open hole gravel pack candidates is listed below.

Advantages of open hole gravel packs
  • Low drawdown and high productivity
  • Excellent longevity
  • No casing or perforating expense
Disadvantages of open hole gravel packs
  • Sometimes difficult to exclude undesirable fluids such as water and/or gas
  • Not easily performed in shale the erode or slough when brine is pumped past them.
  • Requires special fluids for drilling the open hole section
Guidelines for selecting open hole gravel pack candidates
  • Formations where cased hole gravel packing has unacceptable productivity.
  • Situations where increased productivity is required.
  • Reservoirs where long, sustained single phase hydrocarbon flow is anticipated.
  • Situations where work over’s 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 maintaining borehole stability in the completion interval
  • Situations where cased hole completions are significantly more expensive (Horizontal wells)

Selection criteria for gravel packing

For better results selection of the gravel and screen plays major role here is a brief discussion on the selection criteria. Design the gravel Pack includes

  • Gravel size[3]
  • Completion type
  • Screen size
  • Transportation of the gravel
Sampling of formation sand

Improper formation sand sampling techniques can lead to gravel packs which fail due to plugging of the gravel pack or the production of sand. Because the formation sand size is so important, the technique used to obtain a formation sample is also important. In well producing sand, a sample of the formation sand is easily obtained at the surface. Although such a sample can be analyzed and used for gravel pack sand size determination, produced samples will probably indicate a smaller median grain size than the formation sand. 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 most cases due to the cost of coring operations.

Sieve Analysis

Sieve analysis is the typical laboratory routine performed on a formation sand sample for the selection of the proper size gravel pack sand. Sieve analysis consists of placing a formation sample at the top of a series of screens which have progressively smaller mesh sizes. The sand grains in the original well sample will fall through the screens until encountering a screen through which that grains size 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.

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 technique most widely used today was developed by Saucier[4]. The basic premise of Saucier’s work is that optimum sand control is achieved when the median grain size of the gravel pack sand is no more than six times larger than the median grain size of the formation sand. Saucier determined this relationship in a series of core flow experiments where half the core consisted of gravel pack sand and the other half was formation sand as illustrated in Figure

Gravel Pack Sand Diagram.
Gravel Pack Sand

Gravel pack well productivity is sensitive to the permeability of the gravel pack sand. To ensure maximum well productivity only high quality gravel pack sand should be used. The API RP582 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.

Although naturally occurring quartz sand is the most common gravel pack material used, a number of alternative materials for gravel pack applications exist. These alternative materials 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 will range from 2 to 3 times the price of common quartz sand.

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.

  • It offers economical methods of sand control
  • Gravel packing covers long interval up to 500 fts
  • While initial installation is economical, a remedial treatment to replace a failed screen may involve an expensive fishing job
  • Cause pressure drop

Slotted Liners or screen without Gravel Pack

In some cases, slotted liners or screens are used without gravel packing to control the formation sand. Unless the formation is 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.

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 wrap screen. Bridging theory shows that particles will bridge on a slot provided the width of the slot does not exceed two particle diameters. Likewise, particles will bridge against a hole if the hole diameter does not exceed about three particle diameters.

Normally, the slot width or the screen gauge should be sized to equal the formation sand grain size at the largest 10 percent level. Since the larger 10 percent of the sand grains will be stopped by the openings of screen, the remaining 90 percent of the formation sand will be stopped by the larger sand. The bridges formed will not be stable and may breakdown from time to time when producing rate is changed or the well is shut-in.

Disadvantage: Another potential disadvantage of both slotted liners and screens in high rate wells is the possibility of erosion failure of the slotted liner or screen before a bridge can form. Using a slotted liner or screen without gravel packing is not recommended as a good sand control technique because some plugging will eventually occur and will almost always reduce the production capacity of the well.

Maintenance and Work over

Maintenance and work over is a passive approach to sand control. This method basically involves tolerating the sand production and dealing with its effects as and when necessary. Such an approach requires bailing, washing, and cleaning of surface facilities on a routine basis to maintain well productivity. This approach can be successful in specific formation and operating environments. The maintenance and work over method is primarily used where sand production is limited, production rates are low, risk of performing some service is low and economically feasible, or in marginal wells where the expense of other sand control techniques cannot be justified. Of importance are the formation characteristics, which determine how much sand is produced and the effects on safety and productivity.

Comparison of technologies

Criteria Gravel pack Resin coated gravel without screens Resin injection
Pressure >1000 Psi 2500-3300 Psi Up to 3300 Psi
Temperature >150 oF <250 oF <250 oF
% of sand control 75% 5% 10%

Latest Technologies for sand control

Shape memory polymers (SMP): SMP is manufactured to a desired shape and size, placed on the outside of base pipe. When exposed to bottom hole temperatures and a catalyst, it expands to its original shape to fully contact the borehole wall. It provides a positive stress on the formation to stabilize the near wellbore region and control sand migration (By baker Hughes)

Expandable sand-screen systems (ESS): ESS is contacting the formation directly, preventing sand movement and reducing skin development. (By weather ford).

Nanoparticle Technology: Nanoparticle fines migration control additive. The in organic nano crystals are capable of fixating formation fines, such as colloidal silica, charged and non-charged particles and expandable and non-expandable clays on to propant particles. (By Baker Hughes)


We must adopt new production practices for managing sand. These involved maintaining hydrocarbons production at a level that is set over the long term to avoid reservoir damage, rather than pushing the wells to the point where sanding occurred followed by a break in production. As a result of adopting these recommendations, oil production has improved and sand production has been greatly reduced. More improved sand control techniques are being researched and developed for new and more challenging environments.


  1. Stephen P. Mathis, "Sand Management: A Review of Approaches and Concerns", SPE European Formation Damage Conference, 13-14 May 2003, The Hague, Netherlands
  2. George E. King, Pat J. Wildt, Eamonn O'Connell, BP America Inc., "Sand Control Completion Reliability and Failure Rate Comparison With a Multi-Thousand Well Database", SPE Annual Technical Conference and Exhibition, 5-8 October 2003, Denver, Colorado
  3. Leone, J.A., ARCO Oil and Gas Co.; Mana, M.L., Consultant; Parmley, J.B., ARCO Oil and Gas Co., "Gravel-Sizing Criteria for Sand Control and Productivity Optimization", SPE California Regional Meeting, 4-6 April 1990, Ventura, California
  4. Wentao Xiang, Pingshuang Wang, China National Offshore Oil Corporation, " Application of Bridging theory on Saucier gravel to examine the sand control effect", SPE Asia Pacific Oil and Gas Conference and Exhibition, 9-11 September 2003, Jakarta, Indonesia