1 Sand Control Introduction Sand control refers to managing/minimizing formation sand and fines production during hydrocarbon production. Formation sand and fines produced with oil and gas can cause erosion and wear of surface & downhole equipment and production facilities resulting in production downtime, expensive repairs, and potentially loss of well control through damaged safety barriers. Excessive sand production can also lead to reservoir compaction and sand accumulation downhole which can lead to loss of production.
1.1 Causes of Sand Production Depending on the reservoir and production techniques, sand production can occur from the moment a well is brought online or at a later stage in the reservoir’s life as it gets depleted. This section summarizes some of the factors which can influence the tendency of a reservoir to produce sand. Degree of reservoir rock consolidation consolidation – This is a characteristic property of the reservoir rock and is a measure of how strongly the individual sand grains are bound together. It is measured as compressive strength with a value below 1,000 psi usually indicating poorly consolidated sands which have the potential for sand production. Production drawdown and rate – The prod production uction of reservoir fluids creates frict frictional ional drag forces which can increase the likelihood of sand production. Ideally, the production rate would be kept below the critical flow rate at which the formation compressive strength is exceeded, but this is often not economically viable. Further, sand free production in unconsolidated reservoirs is often associated with the formation of arches (or bridges), which are defined as hemispherical caps of interlocking sand grains (like the stones in an arched doorway or bridge). These structures are generally stable at a constant drawdown and flow rate, preventing sand movement, but collapse during shut-ins or other changes in production conditions, causing sand to be produced until a new arch forms. Reduction of pore pressure – pressure – The overbur overburden, den, defined as the weigh weightt of the rock above the reservoir reservoir,, is supported by the combined effect of the formation rock and the pore pressure within it. As the reservoir pressure decreases during the producing life of the well, the stress on the formation rock increases until it begins to fail. Sand grains may then break loose from the matrix, or may be crushed, creating fines that are produced along with the reservoir fluids. Viscosity of reservoir fluids – The frict frictional ional drag force exerted on the formation sand grains is directly related to the viscosity of the reservoir fluids being produced. Higher viscosities will apply a greater frictional drag force on the formation sand grains which means that very viscous hydrocarbons, such as those in heavy oil reservoirs, can cause reservoir sand/fines to be produced even at low flow rates. Degree of water cut – Despite varying field observations, it is gener generally ally accepted in the Oil & Gas industry that water cut increases the risk of sand production in hydrocarbon reservoirs. In many cases it has been observed that the initiation of sand production, or the increase in produced sand volume if already initiated, coincides with water breakthrough. Several hypotheses may help 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 in-situ water surrounding each sand grain. At the onset of water production, the in-situ water tends to cohere to the produced water, resulting in a reduction of surface tension forces and grain-to-grain cohesiveness. A second mechanism by which water production affects sand production is related to the effects of relative permeability. For most reservoirs, the relative permeability of the oil decreases as the water cut increases, thus increasing the destabilizing forces on the sand grains for an equivalent production rate prior to water breakthrough.
1.2 Sand Control Methods Various methods are used in the industry to control sand production and can be broadly classified as either mechanical or chemical. Mechanical methods of sand control prevent sand production by stopping the formation sand with down hole filters (e.g. liners, screens or gravel packs), while chemical methods involve injecting consolidating materials, such as resins, into the formation to cement the sand grains. This section summarizes the most common sand control techniques in use today. In-situ Consolidation – Consolidation – This method involves pumping liquid resins into the formation which then hard harden en to consolidate the individual sand grains and increase its unconfined compressive strength (UCS). If successful, the increase in formation compressive strength should be sufficient to withstand the drag forces while producing at the desired flow rates (it is important to keep in mind that, as this technique is generally applied in marginal wells, the desired flow rates are relatively low). Three types of resins are commercially available: epoxies, furans (including furan/phenolic blends), and pure phenolic. The resins are usually pumped in liquid form, with a catalyst or curing agent is used for hardening, but can also be applied directly to the gravel (resin-coated gravel). The catalyst is either pumped separately or mixed into the resin solution at the surface, requiring time and/or temperature to activate. In-situ consolidation is generally used in marginal wells where a low cost sand control technique is required, which is also helped by the fact that it does not
require any hardware to be deployed. However, there are some disadvantages of using resins for sand control which generally limit their wider application: It is difficult to get complete zonal coverage with resin treatments, so their application is generally limited to perforated intervals of 20-30 ft. Resin treatments are generally limited to formations with temperature < 250 °F. Resin treatments generally lead to an impairment of the formation permeability up to 60 %.
Figure 1: In-Situ Consolidation Standalone Screens and Slotted liners – liners – This sand control technique involves the installati installation on of mechanical down downhole hole filters across the producing interval, in the form of screens or slotted liners, which allow hydrocarbons to pass through but contain formation sand. Most of these filters have a fixed opening which can be varied during manufacturing and is normally sized to be equal to the formation sand grain size at the largest 10th percentile 1 , 2 . The sand control mechanism then relies on the formation of a natural sand pack; the larger sand grains form stable arches (or bridges) against the filter with progressively smaller grains forming similar arches behind them. While it is a relatively simple solution, standalone screens and slotted liners are best suited to well-sorted, clean sands with large grain sizes, as they can otherwise become susceptible to plugging. In addition, the natural sand pack formed is inherently unstable and can breakdown during changes in rate or drawdown, increasing the likelihood of sand production and filter erosion while new bridges form, which is especially problematic in high rate wells.
Figure 2: Open Hole Standalone Screens Pre-Packed Screens – Screens – These screens consis consistt of a thin layer of resin-coated gravel packed between 2 jackets of wire wrapped screen. They can be used by themselves, as a replacement for a gravel pack, or in conjunction with a gravel pack, providing a backup filtration layer in the case of incomplete packing. These types of screens find limited application as they generally tend to plug over time leading to high skins and eventual failure due to hot spots 3 .
Figure 3: Pre-Packed Screens Gravel Packs - While the selection of sand control completion depends on knowledge of the formation properties and will vary with geographic location, gravel packing has been a globally dominant technique since the turn of the century 4. In gravel pack operations, a screen is placed in the wellbore and the surrounding annulus is packed with high permeability gravel sized to prevent the passage of formation sand. The main objective is to stabilize the formation while causing minimal impairment to well productivity, which means that it is critical to completely pack the space between the screen
and formation, preventing the movement of formation sand. If properly designed and installed, a gravel pack will maintain its permeability under a broad range of producing conditions. Gravel packs can be executed with a variety of techniques with the selection depending on various criteria, including the reservoir conditions (e.g. pore and fracture pressures), drilling technique (e.g. WBM, SOBM) and completion hardware (e.g. washpipe and screen size). The most commonly used techniques are:
Figure 4: Open and Cased Hole Gravel Packs Alpha/Beta (Water) Packing – This is the most commonly used gravel packing technique for open hole horizontal completions, involving the pumping of completion brine with gravel concentrations up to 1 PPA. Due to the use of low viscosity carrier fluid, gravel is suspended by the turbulence generated in high velocity fluid flow and so packing is dominated by gravity, resulting in a toe-to-heel packing trend in (near) vertical wells known as the beta-wave. However, in (near) horizontal wells, packing occurs through two sequential events called the alphaand beta-wave respectively. Once slurry enters the highly inclined section of the wellbore, gravel particles begin to settle by gravity, forming a “dune” known as the alpha-wave, while fluid flow above the dune continues to carry gravel particles further downstream. As a result, the alpha-wave continues to extend until it reaches the toe of the well, at which point the beta-wave is initiated in the reverse direction (toe-to-heel, as before). Pressure builds steadily during the beta-wave as the carrier fluid is forced into the narrow annulus between the washpipe and screen basepipe over an increasing length. The main causes of failures in alpha/beta completions are excessive fluid loss, which can be caused by filter cake erosion, swabbing or fracturing, and loss of wellbore integrity, which can be caused by reactive shale swelling or collapse. Slurry Packing – Packing – This involves the use of a vis cous carrier fluid f luid which minimizes gravel sett settling ling and so prevents the deposition of an alpha-wave. Consequently, the aim of any slurry pack design is to pack the entire length of screens in a beta-wave fashion while maintaining the surface and bottomhole pressures within all equipment limitations and below the formation fracture pressure. This technique can be an attractive replacement to water packing when it avoids exceeding fracture pressure by allowing the treatment to be pumped at lower rates. In addition, this technique enables the use of higher gravel concentrations and may find application in scenarios where savings in rig time offset the additional costs associated with the viscous carrier fluid. The main causes of failures in slurry pack completions are similar to those summarized for alpha/beta, except that these treatments can be pumped at lower rates as the gravel is suspended by viscosity, not velocity.
Shunt Tube Technology – This incorporates tubes in the screen design, which can be placed internal or external to the base pipe, creating a secondary path for the slurry to be delivered to voids in the pack if necessary. Packing proceeds in the same way as slurry packing until a bridge forces fluid to divert through the shunt tubes, at which point it may continue by a number of different mechanisms depending on the well conditions and hardware configuration. Shunt tubes provide assurance of the ability to place a complete gravel pack and are used in wells where other techniques are unlikely to succeed and/or high value projects where sand face integrity is critical to long-term success. Frac-Packs – Frac-packing involves the simultaneous hydraulic fracturing of a reservoir and the placement of a gravel pack. With screens already in the wellbore, the fracture is created by injecting a high-viscosity carrier fluid into the formation at bottomhole pressures exceeding its fracturing pressure. The subsequent gravel-laden pumping stages then pack the fracture, with the aim of maximizing its conductivity, before continuing to pack the wellbore annulus between the screen and casing. The combined effect is a fracture (normally 30-50 ft. in length) which helps bypass near wellbore damage caused during drilling and perforating operations, and a gravel pack that prevents formation sand from being produced. However, frac-packing cannot be applied in all situations. It is inappropriate where the reservoir has a gas cap, for example, and may also be unsuitable where there is no effective barrier between the reservoir zones and underlying aquifers.
Figure 5: Frac-Pack High Rate Water Packs (HRWP) – These are gravel packs pumped above fracture pressure with the aim of placing a short (5-15 ft.), relatively thin fracture using low concentrations of gravel with water as a carrier fluid. They are installed in the same way as frac-packs but can help save the cost of fracturing fluids and breakers while retaining some benefits of fracturing. Consequently, they are generally preferred over frac-packs in wells where a low cost completion is needed as well as where the risk of fracturing into a water or gas zone is deemed unacceptable.
Figure 6: High Rate Water Pack (HRWP) Rate Control – This method involves restricting the production rate of the well below the critic al rate at which the formation compressive strength is exceeded. This reduces the drag forces on the sand grains and minimizes the likelihood of sand production, but it is generally unacceptable due to the critical rate being below the economically acceptable limit to operate most wells. In this section, we have discussed various sand control techniques, their selection criteria and relative advantages and disadvantages. More detailed information on the performance of each technique under field conditions is outside the scope of this text but the interested reader is referred to the following publications 5,6,7
2 Well Sand control operations are performed in both land and offshore wells with virtually any deviation, ranging from (near) vertical (<30 degrees) to horizontal (90 degrees) and even fishhook (>90 degrees). In general today, cased hole completions tend to dominate the lower deviation applications, with open hole completions becoming more popular at higher deviations, especially in deep water applications that require longer intervals and increased productivity. Each well and technique poses its own set of challenges and considerations, both in simulation and evaluation, which must be assessed on an individual basis to optimize the completion.
2.1 General Data Sand control design and success is affected by many factors, the most basic of which are properties of the well itself. As with any treatment, gravel packs must be designed on an individual well basis to ensure that the optimum solution is achieved. Consequently, it is very important that the necessary well data is considered in the simulation and updated during the drilling phase.
2.1.1 Survey The survey defines the trajectory of the wellbore in terms of depth and direction. It plays a very important role in the gravel pack design stages because it will have a significant effect on pressure calculations and packing mechanisms. It generally comprises the following measurements at a number of discrete points along the trajectory: Measured Depth (MD) – The length from surface to a particular point in the well, following the trajectory. This will affect friction pressures, which depend on flow path length. Deviation – The angle, or inclination, of the wellbore as measured from the vertical. This will affect packing mechanisms and gravel settling. Azimuth – The compass direction of the wellbore as measured from the geographic or magnetic north pole. This has no effect on gravel pack simulation. True Vertical Depth (TVD) – The vertical length from surface to a particular point in the well (this will always be less than or equal to the measured depth at the same point). This will affect the hydrostatic pressures, which depend on vertical fluid head. The final survey would not be confirmed until the well is actually drilled so the planned survey is normally used for simulation purposes, although this must be updated if there are any significant changes during drilling.
2.1.2 Location Type Gravel packs are routinely performed on both land and offshore wells, including deep-water applications. While there is always additional complexity and operational risk with increasing water depth, the design of the gravel pack must also take into account several key factors in each: Temperature profile – Land wells have a linearly increasing temperature from surface to TD, while offshore wells actually exhibit a cooling trend in the water before increasing linearly. These temperature changes can affect fluid properties and must be considered during the design stages. Riser – Offshore wells have a riser which can add significant volume to the system. This must be considered in both volumetric displacement and friction pressure calculations. Subsea BOP –A subsea BOP in an offshore environment may add significant additional friction if returns are taken through the choke & kill line, since flow must travel through an additional length of pipe to get between the seabed and rig floor. This will affect bottomhole and surface pressures so must be considered during the design and planning stages.
2.1.3 Treatment Type Gravel pack treatments can be broadly split into two main types: alpha/beta and slurry packs. The former involves low viscosity carrier fluids with low gravel concentrations which result in the deposition of an alpha wave, while the latter involves higher viscosity and concentrations which keep the gravel suspended and prevent the alpha wave. Slurry packing can be extended to incorporate shunt tube technology which will affect both the simulation and evaluation of the treatment. The most appropriate treatment must be selected for a given well, which can be influenced by a number of factors. Generally, alpha/beta is the simplest, lowest cost option and is offered by all service providers, but the application of this technique is not recommended when there is a risk of fracturing, hole instability due to the presence of shale’s or when well is drilled with oil-based mud. Slurry packing can become attractive when rig logistics make alpha/beta difficult, when its reduced time of treatment makes it more economically viable (especially in higher rig cost environments), and/or when its drag reducing carrier fluid and the ability to pump at low rates enables the treatment to be placed below the fracturing pressure. Shunt tube technology is generally used when there is a risk of exceeding fracture pressure with both alpha/beta and slurry packing, the well is drilled with oil-based mud, or when the guarantee of sand face integrity is crucial for the success of the project.
2.1.4 Temperature Profile Changes in temperature during circulation can affect the properties of some fluids, especially VES and some polymeric fluids, so it is important to know both the static and circulating temperature profiles:
Static Profile – This increases linearly by vertical depth from the surface temperature to the reservoir temperature at the bottom of the well, following the geothermal gradient. Circulating profile – This follows the same trend as the static profile, but will have a lower bottom hole temperature due to the cooling effect of fluid circulation. The degree of cooling can be estimated based on fluid properties along with circulation rates and times. Offshore wells – For offshore wells, the static and circulating profiles will exhibit two linear trends: the first is from surface temperature to the sea bed temperature (usually defined at around 2-5 degC), and the second is from sea bed temperature to the bottomhole static/circulating temperature (as defined above).
Figure 7: Static and Circulating Temperature Profiles
2.2 Casing Data The casing string is the outer-most pipe string which extends from the surface to the reservoir interval, maintaining wellbore integrity and size. While there can be multiple concentric casings (conductor, surface, intermediate, etc.), only the production casing and liners are generally considered in gravel pack design. Since the completion is run with these casings, they define the annular dimensions which will effect volumes and friction calculations. There are three main types of pipes in the casing string:
2.2.1 Casing This is a normal solid casing with conventional pipe properties (OD, ID, weight, etc.) and determines the flow area available in the annulus Top MD – The measured depth at which the casing starts. This is usually at the surface unless it is a liner. Bottom MD – The measured depth at which the casing ends. Outer Diameter – The outer diameter of the casing pipe body. Inner Diameter – The inner diameter of the casing pipe body. Weight – The mass of the casing per unit length (e.g. lbs/ft in oilfield units).
2.2.2 Open Hole Open hole sections do not have any casing and expose the reservoir completely. These are increasingly used for longer intervals with higher production rates, but also introduce some risk due to stability issues. Open holes have the following properties in addition to those defined for casing: Reservoir Pressure Gradient –This defines the pore pressure as a linear function of true vertical depth for a given open hole section (e.g. psi/ft in oilfield units), which is always less than the fracture gradient. This is important for determining the minimum completion fluid weight required for well control. Fracture Pressure Gradient – This defines the fracture pressure as a linear function of true vertical depth for a given open hole section (e.g. psi/ft in oilfield units), which is always greater than the reservoir pressure gradient. With the exception of high rate water packs, gravel pack treatments are generally designed below fracture pressure. Loss Zone – Unlike the casing, the connection with the reservoir in open hole sect ions means that fluid can flow between the wellbore and reservoir. Consequently, it is necessary to identify and simulate the extent to which this happens as it will affect fluid rates, gravel concentrations and packing mechanisms. In more extreme situations, significant losses can cause premature bridging and incomplete gravel packs.
2.2.3 Perforated Casing Perforated casing is used in cased hole completions and is a casing (as above) which has been perforated with explosive charges to connect it to the reservoir. It therefore has the combined properties of both casing and open hole with the addition of the perforation properties summarised below. These not only affect the flow into and out of the reservoir, but also need to be packed to ensure effective sand control which will obviously affect the design of the gravel pack treatment. Perforation Diameter –The diameter of the entrance hole made in the casing by the explosive charges. Perforation Tunnel Length – The radial length that each perforation extends into the reservoir. Perforation Volume – The volume of gravel which can be packed into the perforations per foot of length (measured depth). Perforation Shot Density – The number of holes in the casing per foot of length (measured depth), which is defined by the number of explosive charges in the perforating gun used.
Figure 8: Perforation Diagram
3 Completion The completion refers collectively to the equipment used in the installation of sand control measures and in the subsequent production/injection of the well. These are split into four strings with each having a specific function in the context of sand control, as detailed in this section: Casing String –This comprises the production casing, perforated casing, and open hole sections detailed earlier in the document. Upper Completion – This comprises the production equipment connecting the lower completion to the surface. Lower Completion – This comprises the bulk of the sand control components, including the screens, packers and fluid loss control valves. Running string – – This is a temporary string used to run and install the lower completion which comprises the equipment required for gravel pack pumping operations, including the service tool, washpipe and downhole gauges.
Figure 9: Open Hole Gravel Pack Completion
3.1 Upper Completion The upper completion string comprises the production tubing as well as any additional production equipment, such as safety valves, chemical injection mandrels and electrical submersible pumps (ESPs). It is installed once the pumping operations have been completed, and the running string pulled out of hole, so is outside the scope of this text.
3.2 Lower Completion The lower completion comprises the bulk of the hardware required for a sand control completion and is run in hole using the running string, with the two being connected at the gravel pack packer. Once set, the packer also forms the anchor point at
the top of the lower completion, ensuring the remaining components below it are located in the correct position. These may include any of the following:
3.2.1 Packers As with most other applications, packers are used for their ability to provide anchoring (preventing movement) and sealing (preventing fluid flow). They are typically set either mechanically, hydraulically or by swelling and are used in a number of scenarios within sand control: Gravel Pack Packer This packer is set, usually mechanically, inside the casing some distance above the reservoir interval and serves as the anchor point for the lower completion. Along with the gravel pack extension and service tool, it also defines the various flow paths required for pumping operations and, once the treatment has been completed, forms the connection point between the upper and lower completion strings. Isolation Packer Isolation packers can be placed between screens to compartmentalize the reservoir section. This allows, among other things, specific sections to be shut off in the future or for the customization of particular hardware, such as Inflow Control Devices (ICDs). Typically, either mechanical or swell packers are used and can also incorporate shunt tube technology if required for the completion, especially in multi-zone cased hole applications. Sump Packer The sump packer is used exclusively in cased hole completions and is normally run in a separate trip, either wireline- or tubing-conveyed, before the lower completion. It is therefore the bottommost component in the completion, acting as a locator to ensure the screens are accurately placed across the perforations as well as forming a solid bottom for the gravel pack during pumping operations.
Figure 10: Common Packer Examples
3.2.2 Gravel Pack Extension This works in conjunction with the gravel pack packer and service tool to define the various flow paths required for pumping operations. It typically comprises a set of ports for directing fluid into the lower completion outer annulus, a seal bore for isolating flow below the ports, and a method of indicating service tool position. Since service tools can differ in functionality and dimensions, the gravel pack extension is normally unique to a specific tool to ensure full compatibility. It is therefore very important that the correct packer, extension and service tool are used in combination.
Figure 11: Gravel Pack Extension Diagram
3.2.3 Quick coupling The quick coupling comprises a thread-less box with an internal seal-bore, which is connected at the bottom of the gravel pack extension, and a thread-less pin with external O-rings, which is connected to the next component in the lower completion. The service tool assembly can then be attached by sliding the box axially over the pin, eliminating the need for rotation and the risk of the service tool disconnecting from the packer during make-up. The O-rings provide a pressure seal between the two components, while set screws lock them together axially and facilitate torque transmission.
Figure 12: Quick Coupling Diagram
3.2.4 Shear Sub This is placed above the screens and blank pipe to provide an emergency disconnect point in case the lower completion needs to be retrieved after the gravel pack is in place. It is activated in tension, the value of which is defined by the number and rating of shear screws used in its assembly, and allows the hardware above the shear sub to be pulled out of hole before returning to clean out the gravel and fish the screens themselves. While it can be used in both cased and open hole treatments, the weight of the longer open hole assemblies often makes the use of a shear sub impractical. Regardless, it is only intended as a backup mechanism and should not be sheared during normal sand control operations.
Figure 13: Shear Sub Diagram
3.2.5 Fluid Loss Control Devices Once the pumping operations have been completed, especially in the case of a stimulation treatment, the well may be susceptible to fluid loss into the reservoir. This has a number of negative implications, including the loss of expensive completion fluid, damage to the reservoir itself and safety concerns, which can be minimized by the use of one of the following fluid loss control devices:
Flapper Valve The most basic version is a flapper valve which is initially held in the open position and closes when the running string is pulled out of hole, preventing fluid from moving into the reservoir. While it is a reasonably cheap and simple option, the flapper valve only seals in one direction and provides no protection should the well take a kick. In addition, it must be broken to restore communication and full-bore flow once the upper completion has been installed, which means that it can only be used once. Formation Isolation Valve (FIV) This can be used instead of a flapper valve and employs a ball-valve seal in both directions, protecting against fluid loss as well as a kick. It is generally mechanically actuated, using a shifting tool, but some versions can also be triggered remotely from the surface (e.g. with pressure pulses). Unlike the flapper valve, the FIV can be actuated multiple times as needed but comes with a much higher price-tag.
Figure 14: Fluid Loss Control Devices Diagram
3.2.6 Y-Manifold This is a specialized piece of equipment designed specifically for eccentric shunt tube systems installed in highly deviated wells (>60 degrees). In this scenario, and depending on the orientation of the shunted screens/blanks, the shunt tubes may be located at the bottom of the wellbore where they may get covered by any settled gravel prior to their activation. The Ymanifold connects to the first joint of shunted screen/blank and converts the eccentric shunt entrances into concentric ones, which ensures that there will always be an entrance open to flow at the top of the wellbore.
Figure 15: Y-Manifold Diagram
3.2.7 Blank Pipe The blank pipe acts as a spacer between the various other components in the string, ensuring correct positioning in the wellbore, while also providing a buffer for gravel placement in two ways: Once the top of the screens has been covered, packing will continue for a short distance along the blanks, which leads to the screenout pressure spike seen at the end of gravel pack treatments. This distance can be calculated using Darcy’s Law for flow through a porous medium and defines the minimum length of the blanks. After screenout, the slurry that is in suspension around the remaining length of unpacked blank pipe provides additional gravel in case the pack settles over time, which may happen in vertical wells if there are any voids along its length. For logistical and practical reasons, the blank pipe is normally selected to be the same as the screen basepipe (i.e. same OD, ID and weight), although it is possible to use other sizes if needed. Blank pipe may also incorporate shunt tube technology if required for the completion.
3.2.8 Screen Screens are the most important components in the lower completion as they provide the mechanical filtration layer required to prevent the sand (formation or gravel pack) from being produced to surface. They are usually located along the entire length of the perforated or open hole interval, with an additional 5-10 feet either side forming a buffer to ensure it is completely packed. Screens comprise a perforated basepipe wrapped in any one of a number of filter media, with wire-wrap and mesh being the most common, and may also incorporate shunt tube or ICD technology if required for the completion. The sizing of filter media for sand control has been the subject of numerous laboratory and modelling studies. Some of these studies have recommended sizing the screens on only the bigger particles (d 10 )8, 9 of the formation PSD with the logic that, after the bigger particles are retained by the filter medium, they will in turn retain the smaller particles and eventually form a natural sand pack which will act as the primary filter. Another study10 takes into account the entire PSD and suggests a safe range of screen opening where both plugging and sand production are unlikely to occur. There are also studies 11, 12 which recommend laboratory screen testing to select the appropriate filter for individual formation sands following their testing procedure and success criteria. Another approach has been to recommend screen selection criteria which are developed from numerical simulations13. As is evident from the above summary, there is a lack of consensus in the industry on a single approach for screen selection which can partly be attributed to the uncertainty in characterizing particle size and failure mechanisms of different reservoirs. Today, the choice of a particular methodology for screen selection usually depends on local experiences and best practises.
Figure 16: Screen Diagram
3.2.9 Washdown Shoe The washdown shoe is used exclusively in open hole completions to facilitate circulation of fluid through the bottom of the lower completion assembly during RIH. This feature is used to clear any debris ahead of the assembly which may cause it to
get stuck and so increases the chance of getting the assembly to bottom. Note that this requires a service tool with washdown capabilities and washpipe extending all the way to the washdown shoe.
Figure 17: Washdown Shoe and Stinger Diagram
3.3 Running String The running string is connected to the lower completion at the gravel pack packer and is used to run it to the required depth. Once the packer is set, the running string is disconnected and can then be moved axially within the lower completion to achieve the various flow paths required during pumping operations. It may include any of the following components:
3.3.1 Workstring This is the pipe which is used to run the lower completion to depth, attaching to the top of the service tool and extending all the way to surface. Since the completion phase is generally conducted directly after drilling, the drill pipe is often used as the workstring to avoid having to change the entire string. There can sometimes be multiple sizes from which to choose, and a tapered string can also be used in wells where there is a production casing with a smaller diameter liner, for example. In addition, the workstring provides the weight required to manipulate the service tool downhole, slacking off and picking up to activate certain features or move between positions. Some joints of heavy-weight drill pipe, if available on the rig, can also be used in the string when additional weight is needed downhole.
Figure 18: Workstring Diagram
3.3.2 Service Tool The service tool has external seals which are used in conjunction with the seal bores in the packer and gravel pack extension to direct the fluid in the required direction during pumping. The various positions are normally located by moving the tool in the axial direction within the stationary lower completion, with all gravel pack tools supporting the main circulating
and reverse flow paths required for any pumping operation. However, some tools will also support other positions to allow for additional flexibility in the pumping design, the most common of which are described in more detail in the pumping section.
Figure 19: Service Tool Diagram
3.3.3 Washpipe Since fluid always takes the path of least resistance, a completion without washpipe will result in the immediate dehydration of slurry at the top of the screens as it tries to take the shortest return path. While this type of gravel pack treatment can be (and has been14 ) successfully completed using shunt tube technology, washpipe is more commonly run from the bottom of the service tool internally along the length screens to force slurry to the bottom before dehydrating and initiating packing. It is normally selected to have a flush connection, so as to minimize the risk of getting stuck inside or damaging the screens, and is also used to convey some of the other hardware components mentioned in this section, such as gauge carriers and shifting tools.
Figure 20: Gravel Packing with and without Washpipe
3.3.4 Tubing Swivel This is connected to the bottom of the service tool and uses a ball bearing system to prevent torque transmission to the washpipe during any rotary operations involving the running string. It is generally only required for completions with long lengths of washpipe, assisting in its making up to the service tool and eliminating any risk associated with its rotation inside the lower completion (e.g. when releasing the service tool using its secondary release mechanism).
Figure 21: Tubing Swivel Diagram
3.3.5 Gauge Carriers Gauges are usually run on the running string to record pressure and temperature at various points in the wellbore during pumping operations, which can later be analysed to get a better understanding of downhole events and packing mechanisms. The gauges must be housed in specially designed carriers, of which there are two main types: Concentric Gauge Carrier – This houses the gauge internally, providing by pass ports to direct fluid flow around it, while still retaining a flush outer diameter. The design makes it ideal for use in the washpipe, although the significantly reduced internal flow area results in a comparatively high friction pressure drop, but it cannot be used in the workstring as the gauge will be exposed to gravel and the risk of erosion. The pressure measurement can be ported either externally (washpipe/basepipe annulus) or internally (in the washpipe), while the temperature measurement will always be that of the internal fluid which is directly in contact with the gauge. Eccentric Gauge Carrier – This houses the gauge externally and so has an increased OD with a reduced ID, which results in a lower friction pressured drop than the same size concentric design. It is often used in both the workstring and the washpipe but the increased OD can cause a problem in some washpipe applications, such as the inability to pass through certain components in the lower completion (e.g. fluid loss control device). The pressure measurement can be ported either externally (washpipe/basepipe annulus) or internally (in the washpipe), while the temperature measurement will always be that of the external fluid which is directly in contact with the gauge.
Figure 22: Concentric and Eccentric Gauge Carrier Diagrams
3.3.6 Pressure Attenuator These are primarily used in alpha/beta gravel pack treatments, where a number of the valves are placed along the length of the washpipe. They activate at a predefined differential pressure, which is set using shear screws during assembly and designed to coincide with the beta packing phase of the gravel pack treatment. Once the activation pressure for a given valve is reached, it slides open and provides a bypass for the fluid to enter the washpipe, effectively short-circuiting the remaining length and so reducing the bottomhole pressure. Pressure attenuators minimize the risk of exceeding the formation fracture pressure, especially on long intervals.
Figure 23: Pressure Attenuator Diagram
3.3.7 Diverter Valve These are placed along the length of the washpipe and can be thought of as permanently open pressure attenuators. By allowing fluid to short-circuit the washpipe, reducing the length through which it has to travel, they reduce the bottomhole pressure throughout the treatment. However, since they are always open, diverter valves will force the slurry to dehydrate and bridge prematurely so can only be used in conjunction with shunt tube technology, which would allow the remainder of the interval to be packed. In addition, they use a check valve system to ensure flow can only occur from outside to inside, allowing them to be used in washdown operations where fluid is pumped internally to the end of the washpipe.
Figure 24: Diverter Valve Diagram
3.3.8 Shifting/Logging tools
The washpipe is often used to convey shifting tools which operate valves, such as the FIV, or sliding sleeves within the lower completion. Other tubing-conveyed logging tools can also be placed towards the end of the washpipe for performing various measurements, such as density for gravel pack evaluation, when pulling out of hole with the running string.
3.3.9 Washdown Shoe Stinger The stinger is used exclusively in open hole applications in conjunction with the washdown shoe and must be placed at the very end of the washpipe. It has a polished surface on which an O-ring in the washdown shoe will seal, allowing fluid to be pumped down the washpipe and out of the very bottom of the lower completion assembly. However, the stinger moves out of the washdown shoe once the service tool is moved into the circulating position to allow returns to be taken through the washpipe during gravel pack pumping operations. Note that this requires a service tool with washdown capabilities.
Figure 25: Washdown Shoe and Stinger Diagram
3.4 Shunt Tube Technology The aim of any gravel pack treatment is always the complete packing of the annulus around the screens to ensure reliable sand control. However, a premature bridge during pumping, perhaps due to excessive slurry dehydration or even wellbore collapse, may leave voids which will likely lead to hot-spots during production and eventual screen failure. Shunt tube technology can be incorporated into the lower completion in situations where this is considered a significant risk, providing an independent conduit along the length of the screens through which the fluid can divert to bypass the bridge. There are a number of shunt tube systems available which generally fall into the categories summarized in this section.
Figure 26: Shunt Tube Principle
3.4.1 Rectangular Packing Tubes This system has multiple packing tubes with nozzles (usually 2-5)15, 16 through which fluid can divert. The tubes are available in two sizes, with the larger having comparatively low friction to support higher rates, which are mounted externally along the length of the screens and blank pipe. The system is generally limited to relatively short interval lengths because, over longer lengths, fluid dehydration through the nozzles will progressively increase the slurry concentration until it becomes too heavy to pump. Consequently, packing tube systems find significant application in cased hole treatments.
Figure 27: Rectangle Packing Tube System Diagram
3.4.2 Rectangular Transport and Packing Tubes A number of transport tubes can be added t o the sys tem (usually 1-2) which have a larger flow area t han the packing tubes and lack nozzles 15,17 . The fluid travels along these tubes and can only divert into the smaller packing tubes at the top of each screen joint, which has the benefit of reducing the overall friction and solving the dehydration problem observed with packing tubes alone. As a result, this type of system can be used to complete much longer intervals and finds significant application in horizontal open hole treatments. The two main configurations are the 1x2 (1 transport and 2 packing tubes) and 2x2 (2 transport and 2 packing tubes), with the latter being shown in the diagram below.
Figure 28: 2x2 Rectangle Transport & Packing Tube System Diagram By design, the transport tubes must extend along the entire length of shunted blank and screen, which results in the need to form connections between one joint and the next during RIH of the lower completion. This is done using jumper tubes that are used to bridge the gap between the shunts on two adjacent joints after they have been made up and torqued, as show in the diagram below.
Figure 29: Jumper Tubes Diagram
3.4.3 Round Transport and Packing Tubes This system comprises 9 identical round tubes, with 6 acting as transport tubes and 3 as packing tubes 18 . Unlike the rectangular systems, these tubes are located inside the screen with nozzles protruding externally. This design provides notable advantages over the rectangular system:
An annular reservoir section built into a special coupling that connects joints together ensures that the shunt tubes automatically connect when made-up without the need for jumper tubes. It is therefore faster and easier to RIH than rectangular systems. The reservoir also connects all shunt tubes together at each joint which means that a blockage in any given tube will prevent flow downstream of it for the length of one joint only (up to the next reservoir section). On the other hand, a blocked tube in the rectangular system will prevent flow in the entire length downstream of it. The internal tubes allow the system to be more easily used with isolation packers (e.g. swell packers) as they do not interfere with the element and sealing, as they would in the external rectangular system. The system has reduced overall friction at a given rate, resulting in the ability to gravel pack greater lengths in comparison to an equivalent rectangular system. As such, it is also primarily used in long horizontal open hole completions.
Figure 30: 6x3 Round Transport & Packing Tube System Diagram
3.5 Inflow Control Device (ICD) Technology ICDs find application predominantly in long horizontal wells where the toe section of the well may not produce due to the high friction pressure associated with moving the fluid from the toe to the heel. They can also help to prevent water coning at the heel and are also used in horizontal wells which are placed close to oil-water or gas-oil contact. ICD technology solves these problems by providing a means of ensuring an even production profile along the length of the wellbore. Each joint of screen is built using solid basepipe, as opposed to the perforated basepipe used in traditional screens, with a number of nozzles fitted at one end. Fluid is then forced to travel along a narrow annulus between the basepipe and filter media before passing through the nozzles, which introduces an additional pressure drop that spreads inflow across the length of the wellbore. The number and diameter of nozzles can be customized and varied along the length of the well, depending on the heterogeneity of the reservoir, to achieve a desired production profile.
4 Fluids One of the most important aspects of successful gravel pack treatment design is the selection of an appropriate carrier fluid. Two main techniques are currently used in executing gravel pack treatments: (1) alpha/beta (water) packing and (2) slurry packing with or without shunt tube technology. The gravel transport and packing mechanisms are completely different for these techniques. Water packing uses low viscosity fluids (typically brine) relying on velocity to transport low gravel
concentration (typically <=1 PPA), whereas slurry packing uses viscous fluids and relies primarily on fluid viscosity to suspend and transport high gravel concentration (typically 4-6 PPA)19 . The advantages and disadvantages of these techniques are discussed extensively in the literature20, 21, 22 .
4.1 Alpha Beta Water packing uses low viscosity fluids (typically brine) relying on velocity to transport low gravel concentration (typically <=1 PPA) and deposit it in the screen annulus. The factors considered in selection of water packing fluids include bottom hole temperature, fluid density needed for well control, compatibility with formation fluids and formation retained permeability19 . In wells with a long horizontal section or with a narrow margin between pore and fracture pressures, the friction pressure loss exhibited by these fluids in critical conduits (e.g. in the washpipe and washpipe/basepipe annulus) also becomes an important factor and governs whether these wells can be gravel packed without fracturing the formation. The following table lists the common completion brines and the maximum densities that can be achieved with each:
Density at Saturation (lb/gal)
Brine Name Potassium Chloride (KCl) Sodium Chloride (NaCl) Sodium Formate (NaCOOH) Calcium Chloride (CaCl 2)
9.7 10 11.1 11.8 12.5 12.7 13.2 13.3
Sodium Chloride/Sodium Bromide (NaCl/NaBr) Sodium Bromide (NaBr) Sodium Potassium Formate (Na-KCOOH) Potassium Formate (KCOOH) Calcium Chloride / Calcium Bromide(CaCl 2/CaBr 2) Calcium Bromide(CaBr 2)
Potassium Cesium Formate (K-CsCOOH) Cesium Formate (CsCOOH) Calcium Bromide / Zinc Bromide (CaBr 2/ZnBr 2) Zinc Bromide (ZnBr2)
15.1
15.3 19.1 19.2 19.2 19.2
4.2 Slurry Packing Slurry packing uses viscous fluids, relying primarily on fluid viscosity to transport high gravel concentration (typically 4-6 PPA). The factors considered in selection of slurry packing fluids include bottomhole temperature, compatibility of the viscosifier with the required brine type, fluid density needed for well control, rheology, sand suspension, compatibility with formation fluids, formation retained permeability, and friction pressure in critical conduits (e.g. washpipe, washpipe/basepipe annulus, workstring/casing annulus and shunt tubes). When shunt tube technology is employed, the friction pressure loss through the shunt tubes defines the maximum length that can be gravel packed without exceeding the system burst and collapse pressure limitations. Thus, friction pressure loss is an important factor in the successful execution of any gravel pack treatment and, at a given geometry and rate, is significantly influenced by the choice of carrier fluid. Because sand suspension properties of these fluids also dictate the lower limit of pump rates, dealing with friction through reduced pump rate is also controlled by carrier fluid properties. Commonly used fluids are viscoelastic surfactants (VES)23, 24, 25 and polymer based fluids, such as Xanthan26, 27 and HEC27, 28 , which exhibit non-Newtonian shear thinning behaviour: VES – This can be formulated in both monovalent (KCl, NaCl, NaBr) and divalent brines (CaCl, CaBr) up to a density of 14.2 lb/gal and temperatures up to 300°F. In the field, continuous mixing of VES is generally preferred (“on-the-fly”) but it can also be batch mixed ahead of time if required.
HEC – This can be formulated up to densities of 19.0 lbm/gal in both monovalent (KCl, NaCl, NaBr) and divalent (CaCl2, CaBr 2, ZnBr 2) brines but is limited to temperatures below 180°F. Unlike VES, this polymer fluid must be batch mixed in the field. Xanthan – This hydrates only in monovalent brines (KCl, NaCl, NaBr, formates) up to a density of 19.0 lb/gal and temperatures up to 350°F. As a polymer fluid, it must be batch mixed in the field and cannot be continuously mixed. These fluids are largely defined by their rheological properties, which should be accurately known to properly simulate gravel pack treatments. This data can be determined through lab testing of fluid samples, which will help define the following properties: Rheology – Gravel packing fluids are generally pseudo plastic power law type fluids that can be defined by the following indices: n’ (Flow Behavior Index) – The slope of a log-log plot of viscosit y vs. shear rate for a power law f luid. k’ (Consistency Index) – The Y-axis intercept of a log-log plot of viscosit y vs. shear rate for a power law f luid. Temperature – The temperature at which the rheology is measured. This input is important as the rheology of most fluids changes with temperature. Lab measurements should be taken at a range of temperatures which covers those expected in the field (e.g. surface, bottomhole static and bottomhole circulating temperatures). Drag Reduction Factor – Most polymeric and VES type fluids used in sand control exhibit lower friction pressure than equivalent Newtonian fluids at similar rates. This phenomenon is called drag reduction and is modeled by interpolating the friction calculations between the 2 envelopes of Dodge & Metzner 29 and Virk30 in proportion to the percentage drag reduction.
5 Gravel The most common gravels/proppants used in gravel packing are re-sieved sands and ceramics with densities ranging from 2.65 to 2.73 S.G.. The gravel concentration is generally <=1 PPA for alpha/beta treatments, but up to 6 PPA for slurry pack treatments (with or without shunt tubes). The following properties of gravel are generally used in modeling the gravel packing process: Density – The absolute density of the gravel is used both in settling and PPA calculations. Mean Diameter – The mean diameter is an important input in settling calculations as larger particles generally have a higher rate of settling. Bulk Density – Bulk density refers to the mass of the gravel divided by the total volume it occupies, which is important for accurately calculating the amount of gravel needed to pack the screen annulus. Pack Permeability – This is the measure of resistance to fluid flow in a packed bed of gravel. This is needed for accurate calculations of packing in the blanks during screenout. Friction Coefficients – These are empirical numbers used to calculate the increase in friction pressure due to additional of gravel in both laminar and turbulent flow regimes. Angle of Repose – The angle of repose of a granular material is the steepest angle of descent or dip of the slope relative to the horizontal plane at which the material is on the verge of sliding. In wells with long open hole intervals or a narrow margin between pore and fracture pressures, the application of alpha/beta gravel packing becomes difficult as the rate required to suspend gravel may result in fracturing of the formation and premature bridging. In these challenging scenarios, the use of light-weight gravel (specific gravity between 1.01 and 2.4 S.G. 31, 32, 33 ), can enable the application of the alpha/beta technique. Lower density gravel can be transported more easily using non-viscous fluids, thus allowing the treatment to be pumped at lower pump rates for similar alpha wave height’s to reduce bottomhole pressures.
6 Pumping While this section forms a general guideline for gravel pack pumping design based on current practices and experience, it is important to remember that any aspect can be varied as necessary and every design should be thoroughly modelled and
verified before execution. For a successful gravel pack design, the following criteria should be met: 100% gravel pack A succ essful sand control treatment should result in complete packing of the screen annulus. Any voids may result in hot-spots during production and eventual screen failure (loss of sand control). Bottomhole Pressure below Fracture Pressure – With the exception of high rate water packs, which are pumped above the fracture pressure by design, fracturing during a gravel pack treatment induces leakoff to the formation which may lead to premature bridging due to excessive slurry dehydration. In some cases, gravel packs can still be completed after fracturing but this is risky and the treatment should always be designed to maintain the bottomhole pressure below the fracture pressure. Surface Rate and Pressure within Equipment Limitations All equipment, both surface and downhole, has maximum working pressures to which it can be subjected. Consequently, it is important to identify the component with the lowest rating in the system and ensure that the pressures never exceed its limit. Additionally, the high-pressure pumps used to execute the treatment must be able to sustain the required horsepower to place the gravel pack. If any of these criteria are not met, the design must be further optimized or changed to ensure that the gravel pack can be placed successfully. In some cases, this may require the use of additional technology.
6.1 Initial Data When designing and simulating sand control treatments, it is very important to understand the initial conditions in the wellbore as they may have a significant effect on the pressures in the system and, consequently, the outcome of the treatment. There are a number of key factors to consider which are summarised in this section.
6.1.1 Wellbore Fluids Friction is heavily dependent on fluid properties and so the fluids already present in the wellbore at the start of the treatment are just as important as those pumped during the treatment. There may be a single fluid in the entire well or multiple fluids, typically with brine above the gravel pack packer and a viscous fluid below.
Figure 31: Wellbore Fluids
6.1.2 Tool Position The service tool position defines how the fluid and gravel will displace through the system during pumping operations. Generally, there are a limited number of standard sand control tool positions, as detailed below, with proprietary tools having additional positions for specific functions. Circulating - The circulating position connects flow between the workstring and lower completion annulus, as well as between the upper annulus and washpipe. This is used for gravel packing operations, allowing gravel to be circulated down the workstring and into the reservoir section, with fluid returns going back up to surface through the washpipe and annulus.
Figure 32: Circulating Position Flow Diagram Squeeze The squeeze position is similar to the circulating one but with the return path closed, either downhole at the service tool or at the surface, effectively forcing any pumped fluid directly into the reservoir. This is used for fracturing operations where fluid is pumped into the workstring at high pressure to create a fracture in the formation, which is then packed with gravel to keep it open.
Figure 33: Squeeze Position Flow Diagram Reverse - The reverse position connects the workstring and upper annulus directly, which isolates the reservoir section below the gravel pack packer. This is used in reverse out operations at the end of all sand control treatments, where fluid is pumped in the annulus to push any excess slurry remaining in the workstring back up to surface.
Figure 34: Reverse Position Flow Diagram Washdown - The washdown position connects flow between the workstring and the washpipe, as well as the between the annuli above and below the packer. This position can be used either before or after the sand control treatment to spot fluid in the reservoir section or to perform cleanout operations. It is most commonly used when running into an open hole, allowing the circulation of fluid past the bottom of the assembly to clear any debris which may cause it to get stuck. However, it cannot be used while pumping gravel-laden slurry due to the erosive damage that will likely be caused to equipment such as the washdown shoe. It is important to note that that not all service tools support the washdown feature.
Figure 35: Washdown Position Flow Diagram Reverse-Port Gravel Pack - This flow path is normally only used when installing alpha/beta gravel packs in fishhook wells (deviation >90 degrees). A specialised service tool allows sand to be transported from the toe to the heel of the well, effectively reversing the traditional circulating flow path. This ensures that the gravel pack can still be placed in a downhill direction for fishhook trajectories and reduces the risk of a premature screenout due to settling or excessive alpha wave heights.34 .
Figure 36: Reverse-Port Gravel Pack Flow Diagram
6.1.3 Pumping Direction Fluid can either be pumped directly into the workstring or into the annulus. Since it is required to keep gravel out of the upper annulus, for a variety of reasons, gravel-laden slurry must only be pumped into the workstring. In sand control treatments, pumping into the annulus is generally only performed in the reverse position when removing excess gravel from the system at the end of the treatment. However, it is possible to pump clean fluid into the annulus in any position.
6.1.4 Annular BOP Position The annular BOP (often called the “Hydril” after the name of one of the manufacturers of such devices) resembles a large rubber donut and is used to open and close the upper annulus at the BOP. In gravel pack operations, it is used to direct the return flow towards the trip tanks in the open position, or through the choke/kill line in the closed position. The former offers reduced friction, which will lower bottomhole and surface pressures, while the latter provides more control on chokes and returned fluids, allowing both rate and density to be monitored as well as facilitating their separation and disposal (e.g. excess gravel and viscous fluids).
6.1.5 Subsea BOP A subsea BOP in an offshore environment may add significant additional friction if returns are t aken through the choke & kill line, since flow must travel through an additional length of pipe to get between the seabed and rig floor. This will affect bottomhole and surface pressures so must be considered during the design and planning stages.
6.2 Schedule The pumping schedule is one of the most important parts of the treatment and must be designed in such a way so as to ensure a full pack while maintaining pressures within the limits of both surface and downhole equipment, as well as the reservoir and fracture pressures. These considerations depend on the type of sand control treatment being performed and are summarised in this section.
6.2.1 Alpha/Beta Packing
Alpha/Beta (Water) packing is the most commonly used gravel packing technique for open hole horizontal completions, involving the pumping of completion brine with gravel being concentrations up to 1 PPA. With this technique, the packing of a horizontal well occurs through two sequential events: Alpha-Wave – Gravel deposition around the screens in the heel-to-toe direction with a conventional circulating flow path (this is reversed in reverse-port gravel packing). Beta- – Gravel deposition around on top of the alpha-wave in the toe-to-heel direction with a conventional circulating flow path (this is reversed in reverse-port gravel packing).
Figure 37: Alpha/Beta Packing Diagram (Circulating Position)
Once the fluid passes through the cross-over tool and enters the highly inclined section of the wellbore, gravity forces cause gravel particles to settle, forming a “dune”, which causes local fluid velocities above the dune to increase and continue to carry gravel particles further downstream. As a result, an alpha-wave deposits in the lower part of the wellbore with an equilibrium height dictated by gravel and fluid properties as well as local velocities. Once the alpha-wave reaches the toe of the well, the beta-wave is initiated, depositing gravel on top of the alpha-wave in the opposite direction back to the top of the screen and into the blank pipe section. During the beta-wave, carrier fluid is diverted into the narrow annulus between the screen basepipe and washpipe and is forced to travel all the way to the end of the washpipe towards the toe. The reduced flow area in this annulus results in an increased friction pressure which builds up steadily with the increasing length of the pack. This may result in pressures exceeding the fracturing pressure of the reservoir, potentially causing a premature screen out and an incomplete gravel pack. The main causes of failures in alpha/beta completions are excessive fluid loss, which can be caused by filter cake erosion, swabbing or fracturing, and/or loss of wellbore integrity, which can be caused by reactive shale swelling or collapse. Design and operations factors, such as incorrect washpipe sizing or poor concentration and rate control at surface, may also negatively affect the placement of the gravel pack. It is therefore very important that all treatments are simulated to identify the best combination of equipment and pumping schedule needed to minimize risk prior to execution. A typical alpha/beta pumping schedule contains the following stages: Slurry Stage – Typically, alpha/beta jobs are pumped at rates between 2-8 bbl/min. The job starts at pump rates between 5-8 bbl/min and gravel concentration between 0.25-1 PPA. The rate is kept constant during the alpha-wave and initial portion of beta-wave deposition but, depending on the margin between pore and fracture pressure, is usually dropped several times during the beta-wave to avoid exceeding the fracture pressure. The volume of this stage is normally calculated such that the total gravel pumped is around 20-30% greater than that theoretically required to pack the reservoir interval, providing a safety margin in case there are any variations. Flush Stage – This is the displacement fluid which is normally the same completion brine used as the gravel pack carrier fluid. This stage is used to displace the slurry in the workstring into the screen annulus for packing and continues until screenout, at which point pumping is stopped. However, if all the slurry is displaced below the packer and screenout does not occur, a second “top-off” job will be required to complete the pack. As a result, the volume of this stage must be at least equal to the displacement volume to the packer, although it is good practice to over-displace the gravel.
In general, the various stages would be pumped at rates up to around 8 bbl/min for most gravel pack treatments. While the rate can be stepped or varied, it is good practice to maintain a constant rate throughout the gravel-laden stages (where possible) to avoid having to make changes in gravel addition rates during pumping. However, the rate may have to be reduced towards the end of the treatment, ideally during the flush stage when gravel is no longer being mixed, to ensure that the pressure remains within the required limits as it increases due to packing.
6.2.2 Slurry Packing Slurry packing involves the use of a viscous carrier fluid which minimizes gravel settling and so prevents the deposition of an alpha-wave. Consequently, the aim of any slurry pack design is to pack the entire length of screens in a beta-wave fashion while maintaining the surface and bottomhole pressures within all equipment limitations and below the formation fracture pressure. There is not a fixed schedule to achieve this, as it must be designed on an individual well basis, but a slurry pack pumping schedule would typically include the following stages:
Figure 38: Slurry Packing Diagram (Circulating Position) Pre-PAD Stage – A volume of clean carrier fluid is pumped ahead of the first slurry stage to provide a buffer for any roping35 36 that may take place in the workstring as well as for mixing/dilution at the leading edge of the slurry, which may lead to gravel settling out. While it is not possible to know the exact extent of these effects without dynamic fluid mixing simulations, a volume of 30-50 bbl is usually reasonable. 2-3 Low Concentration Stages – These form a stepped ramp building up to the main (maximum) concentration stage and minimize the risk of high concentration “slugs” due to issues with the surface equipment. It is important to minimize the stage volumes so as not to waste too much carrier fluid, but enough volume must be pumped to allow the surface equipment to stabilize at each stage, usually in the order of 15-20 bbl. 1 High Concentration Stage – Typically, gravel packing treatments are performed at a constant gravel concentration up to around 6 PPA, although this can be varied based on fluids and design. This approach favours constant hydrostatic conditions (once the gravel is displaced below the packer) so allows the surface pressure responses to be interpreted more easily during the treatment. The volume of this stage is normally calculated such that the total gravel pumped is around 20-30% greater than that theoretically required to pack the reservoir interval, providing a safety margin in case there are any variations. Post-PAD Stage – This is another buffer stage using clean carrier fluid which is pumped once gravel is cut to ensure that any remaining gravel is effectively displaced through the surface lines and into the workstring. It is typically comparable in volume to the pre-PAD stage. Flush Stage – This is the displacement fluid, typic ally brine, which is used to displace the slurry in the workstring into the screen annulus for packing. Generally, this stage continues until screenout, at which point pumping is stopped. However, if all the slurry is displaced below the packer and screenout does not occur, a second “top-off” job will be required to complete the pack. As a result, the volume of this stage must be at least equal to the displacement volume to the packer, although it is good practice to over-displace the gravel. In general, the various stages would be pumped at rates up to around 10 bbl/min for most gravel pack treatments. While the rate can be stepped or varied, it is good practice to maintain a constant rate throughout the gravel-laden stages (where
possible) to avoid having to make changes in gravel addition rates during pumping. However, the rate may have to be reduced towards the end of the treatment, ideally during the flush stage when gravel is no longer being mixed, to ensure that the pressure remains within the required limits as it increases due to packing.
6.2.3 Shunt Tube Packing As detailed in section 3.4, shunt tube technology can be incorporated into the lower completion in situations where premature bridging is considered a significant risk, providing an independent conduit along the length of the screens through which the fluid can divert to bypass the bridge. Since all shunt tube systems use identical principles, the design of any pumping treatment involving this technology follows the same general process. Shunt tubes are intended as a backup mechanism and will not activate if an annular bridge does not form, in which case the treatment would be expected to proceed as a slurry pack. However, when they do activate, packing and pressure trends can become somewhat complex as they are heavily dependent on downhole events, such as fracturing and losses, completion hardware configuration, such as whether or not washpipe is used, and fluid properties. The main pressure trends associated with shunt tubes are illustrated in the chart and summarized below.
Figure 39: Shunt Tube Packing Surface Pressure Response Shunt Activation – After a bridge occurs, packing will continue to the top of the screens before fluid is forced to divert through the shunt tubes. The restricted flow area causes a sudden increase in friction, known as shunt activation, which is proportional to the length of tubes required to bypass the bridge. Toe to Heel Packing – Once the slurry exits the shunt tubes below the bridge, it can continue to flow in the screen annulus towards the toe of the well before packing (same as a slurry pack). This produces the same linear pressure increase observed during conventional slurry packing prior to shunt activation (toe to heel beta wave). Heel to Toe Packing – In some scenarios, such as the presence of signific ant losses at the shunt exit point, the slurry can immediately dehydrate and extend the pack in a heel to toe direction. This forces fluid to travel increasingly greater distances in the shunt tubes before being able to exit, which results in a steeper pressure gradient. Note that this trend will always dominate in treatments without washpipe as the slurry will immediately dehydrate on exiting the shunts. In reality, the packing trend after shunt activation is a combination of both “toe to heel” and “heel to toe” packing, resulting in a pressure gradient lying between the two extremes on the chart. Regardless, when designing a gravel pack with shunt tubes, it is best to first design the treatment as a slurry pack (i.e. assuming no shunt tubes) which will provide the best chance at placing the gravel successfully from the outset. Once completed, the limits of the shunt tube system must be considered to ensure that they are not exceeded should it be activated for any reason. There are two main scenarios to consider:
Burst Rating – Ass uming that the pack does not provide any additional external support, the greatest burst pressure will occur just below the top of the gravel pack (assuming no flow through the pack). At this location during shunting, the difference between internal and external pressures is approximately equal to the friction of the length of downstream shunt tubes (neglecting hydrostatic changes). Therefore, the worst case burst pressure will be experienced when flow occurs in the full length of shunted screens. Collapse Rating – The greatest collapse will occur just above the top of the gravel pack (assuming no flow through t he pack). At this location during shunting, the difference between external and internal pressures is approximately equal to the friction of the length of upstream shunt tubes (neglecting hydrostatic changes). Therefore, the worst case collapse pressure will be experienced when flow occurs in the full length of shunted blanks. The magnitudes of these ratings will define the maximum rate that can be safely pumped through the shunt tube system without exceeding either one. If shunt activation is observed during execution, marked by a characteristic activation pressure jump, the pump rate must be reduced below the determined maximum rate. The job can then continue through the shunt tubes to completion, although the rate may need to be further reduced to ensure pressures remain within other equipment limitations.
6.2.4 Design Optimization Any gravel pack design must be optimized to ensure, at a minimum, that it meets the basic succ ess criteria listed earlier. This can be achieved by varying a large number of parameters, although a lot may have already been fixed for practical and logistical reasons, but the following are the easiest to control: Pump Rate – Lower rates will reduce the bottomhole and surface pressure to bring them within equipment limitations, while higher rates are better for slurry mixing and proppant transport. Consequently, the minimum rate will be defined by the mixing ability of the surface equipment and slurry transport considerations, while the maximum rate will be defined by equipment working pressures or reservoir fracture pressure. Fluid Type and Gravel Concentration – Fluids should always be formulated to meet the sand suspension requirements for the treatment, which is normally tested in the lab. However, higher densities, viscosities and gravel concentrations generally increase friction and pressure. It is also possible to add friction reducers in some applications to lower the system pressures within the required limits. Washpipe Ratio – Washpipe plays a significant role in defining friction pressure, especially on longer intervals. Generally, larger washpipe will reduce the friction internally during circulation, but increase it externally (washpipe/basepipe annulus) during packing. Smaller washpipe has the opposite effect, increasing internally but decreasing externally, so this must be balanced. As a “rule of thumb”, the ratio of washpipe OD to basepipe ID is selected to be around 0.8, although must still be modelled on an individual well basis. Washpipe Accessories – Any access ories connected to the washpipe (gauge carriers, shifting tools, etc.) will add friction and serve to increase both bottomhole and surface pressures. Removing these, where possible, will reduce these pressures but that is not always practical. Using a different accessory design may also prove beneficial, such as replacing internal gauge carriers with external ones, which tend to have significantly lower friction.
7 Evaluation There are many ways to analyse sand control treatment downhole gauge data, with the majority looking for trends in the measured pressures. The most valuable method is the use of friction pressure. This method relies on the fact that, in a circulating system such as that used for open hole gravel packing, the pressure recorded by any downhole gauge is the sum of the hydrostatic and friction pressures:
In a given well, the hydrostatic pressure varies only with fluid density and displacement, and can be calculated throughout the treatment. As such, the friction pressure yields the most insight into downhole events. Eq. (1) can then be rearranged to obtain the following relationship:
Therefore, removing the hydrostatic pressure from the gauge pressure allows for a more direct analysis by eliminating any data that may mask small, yet potentially significant, changes in the friction pressure. In addition, because friction changes upstream of a gauge do not affect its reading, this approach narrows down the location of the event causing the change to the flow path ahead of the gauge. This type of friction pressure analysis is very useful when applied to a single gauge, but is even more powerful when extended to multiple gauges in a well.
Figure 40: Friction Pressure Analysis with Multiple Gauges Ass uming two gauges in a circulating system, gauge 1 at an arbitrary point in the flow path and gauge 2 further downstream, the following holds true at each gauge: At gauge 1:
At gauge 2: Taking a difference between the two friction pressures (Eq. (3) – Eq.(4)) gives the following relationship:
Because the friction pressure at each gauge is that for the flow path ahead of it, Eq. (5) defines the friction pressure for the section of the flow path between the two gauges, which is independent of events in the remainder of the system. This is an extremely useful method for analysing downhole data due to the fact that the friction trends observed can now be attributed to events occurring between the two gauges concerned; thus, allowing them to be more accurately located and tracked through the system. It is recommended that a minimum of three gauges be placed along the open hole interval to have at least two discrete friction pressure sections for analysis, but additional gauges will significantly improve the resolution. There are a number of factors that can affect the friction pressure, including rate, fluid properties, wellbore geometry, and flow path length among others. Because many fields employ similar completion types and treatments between wells, the majority of these variables are consistent from job to job, with the exception of flow path length that will depend on the well trajectory and gauge placement. However, if it is assumed that the friction is distributed uniformly along each section, Eq. (5) can be normalized by approximating the flow path length to the difference in measured depth (MD) between the two gauges:
This normalized friction pressure allows for a more direct comparison between similar jobs, improving the ability to predict friction pressures on future treatments and identifying inconsistencies. 37
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