Well Displacement – Oil Well Pre-Completion

Introduction

Once the well is drilled to TD, it should be displaced to a clean, solids-free completion fluid before commencing with the completion. During the transition from drilling mud to completion fluid, the fate of the well is very often determined since it is estimated that a third of all failed completions are due to poor debris management. Regardless of the completion method, all displacements are designed to achieve the following:

• Remove the drilling mud from the wellbore, and ensure that the casing, riser, and/or open hole are free of drilling mud residue
• Minimize fluid interface and associated waste during the transition from drilling mud to completion fluid (i.e. minimize disposal costs)
• Reduce non-productive time (i.e. rig time)
• Reduce filtration time
• Maximize well productivity
• Perform the operation with high QHSE standards

To achieve these objectives, all displacements must consider the essential elements of wellbore cleaning: mechanical cleaning, chemical cleaning, and proper hydraulic design. Regardless of the mud system or completion method, these elements are critically important and therefore must be considered.

Mechanical Wellbore Cleaning

It is important to understand the client’s objectives when designing a mechanical wellbore cleaning string. Weatherford’s mechanical wellbore cleaning tools are designed to work in a single trip. This means that multiple operations can be performed using a single clean-up string. This flexibility provides the client with significant cost savings and dramatically reduces the number of trips (i.e. cuts down on rig time). Some possible simultaneous operations are:

• Drilling out cement shoes / bridge plugs to establish a new plug-back total depth (PBTD)
• Drift the casing, ensuring that the lower completion can be run without problems
• Clean the liner top so that debris does not fall back into the producing zone
• Jet the BOP and collect any dislodged debris, thus keeping it from going downhole
• Boost the annulus to ensure that solids and debris flow back to the surface
• Scrape the casing (including all packer set points) to remove scale and mud solids
• Brush and clean the riser to remove debris
• Filter the downhole fluid while pulling out of hole (POOH), thus validating the displacement

These are just a few operations that can be performed using a single wellbore clean-up string. Additional operations may be performed as required by the client.

Chemical Wellbore Cleaning

Chemical spacers are designed to work in conjunction with mechanical wellbore cleaning tools to remove debris and leave downhole tubulars water-wet. Improper chemical design can lead to the following:

• Chemical incompatibilities that create emulsions or precipitation
• Contamination of completion fluid, leading to long filtration time and high disposal costs
• Improper removal of drilling mud, resulting in oil-wet downhole tubulars
• Solids and debris settling out in the chemical spacers due to improper rheology
• Inducing formation damage by changing rock wettability
• Reduction of rock permeability by particle plugging and/or emulsification with production fluids
• Crystallization of completion fluid or formation of gas hydrate

Each mud system is different, so it is important to customize the chemical spacer train to the specific drilling mud to eliminate the potential issues above.

Filtration and Surface Cleaning

Equally critical but sometimes overlooked aspects of a successful completion operation are cleanliness of surface facilities and filtration of completion fluid. If mud solids or residue are left in the pits and lines, they will mix with completion brine thus contaminating it. Additionally, solids-laden brines (even at very low concentration) have the potential to partially or completely plug the producing zone.

Filtration equipment is operated continuously during all phases of completion operations, when completion fluids are in the hole, with the objectives of:

• Removing solids from completion fluid
• Protecting the producing formation
• Improve recovery of completion fluids and brines
• Ensuring tool operability
• Prevent solids accumulation in the well annulus
• Safeguard the completion assembly from particle settlement
• Reduce waste volumes
• Meet discharge compliance legislation

All of these subjects will be discussed in greater detail in subsequent sections.

Transition from Drilling Phase to Completion Phase

What is a displacement?

Simply put, a displacement is when the drilling mud is removed from the wellbore and replaced by a solids-free completion fluid. Solid debris and hydrocarbon residues are removed along with the drilling mud. This is accomplished by pumping a series of cleanup fluids through the wellbore and using specialized tools to clean the casing wall, capture solid debris, and improve flow in critical areas of the well. Each displacement must be planned for the specific well conditions that will be encountered since no two wells are exactly alike.

Completion Basics

A well completion is the process of establishing a path through which oil and gas can flow into the wellbore from the surrounding formation. The amount of oil and gas that can be produced is directly linked to the success and efficiency of the completion. There are two categories of well completions: cased hole and open hole.

Cased Hole Completions

A cased hole completion is one in which casing that has been cemented in place along the zone of interest is perforated to allow formation fluids to flow into the well. Perforating guns are run in hole using wireline or tubing. Once they are at the appropriate depth, a series of shaped charges are detonated which propels molten metal outwards through the casing wall. The molten metal also travels a short distance into the surrounding rock formation. Depending on the well, one or more separate zones may be perforated before the production tubing and associated equipment is installed. Cased hole completions have the advantage of greater well stability but restrict well productivity to some degree. They are the most common method.

Open Hole Completions

An open hole completion is one in which the producing zone is left uncased and oil and gas flow directly into the hole created by the drill bit without having to pass through perforations. The simplest type, called a “barefoot completion”, is a method where no special completion equipment is installed; the oil and gas flows directly into the borehole and up to surface through the casing or production tubing. This method is very rarely used since the borehole can become unstable and collapse, and also because sand and formation fines flow into the wellbore along with the oil and gas. This can damage surface equipment and require costly workover operations. A more common method is to install a sand screen or slotted screen, which support and keep the borehole open while limiting the production of solid particles to the surface. Open hole completions have the advantage of greater well productivity but are not as stable as cased hole completions.  

Why do we need to displace drilling mud out of the well before a completion?

Drilling mud is designed to do a variety of important tasks, among them:

• Provide sufficient hydrostatic pressure to prevent formation fluids from flowing into the wellbore
• Provide sufficient hydrostatic pressure to prevent wellbore collapse
• Cool and lubricate the drill bit

• Form an impermeable filter cake to minimize fluid losses and associated formation damage
• Carry drilled solids to the surface

These design requirements mean that drilling muds often contain a high solids concentration (to increase density) and polymers or starches (to improve filter cake building and solids carrying capacity). Despite their usefulness while drilling the well, these same materials are undesirable during well completions. This is because they have a tendency to damage the rock formation itself and restrict the flow of oil and gas. This occurs because of solid particles plugging the pore throats through which oil and gas flows. It is also possible to damage the formation by causing a chemical reaction between the drilling mud and formation fluids. Therefore, the best practice is to completely remove the drilling mud from the well prior to any completion activities and replace it with a non-damaging fluid.

Displacement Objectives

An effective displacement involves mechanical, hydraulic, and chemical components. If proper planning is ignored in any of these three areas it will compromise the effectiveness of the other two. All aspects of the displacement should be combined into a single run to save rig time and minimize expense to the operator, if possible.

Mechanical Wellbore Cleaning Objectives

A complete line of wellbore cleaning tools needed. This includes non-rotational scraper and brushes, string magnets circulation subs, downhole filtration tools, junk baskets, swivel tools, de-burring mills, liner top dress mills, and BOP cleaning equipment. Typical applications for this equipment include:

• Removal of scale, rust, and/or paraffin from casing walls to achieve a consistent drift diameter and ensure that critical completion tools can reach the target zone
• Brushing and polishing of packer set points to allow expansion of elastomer seals onto a clean surface
• De-burring of perforation burrs or gouged casing
• Preparation of the liner top PBR for a tie-back packer

Along with proper application of tools within the string, adequate pipe rotation and reciprocation is vital to the success of the displacement. Rotation of at least 80 rpm and reciprocation of +/- 1 stand should be maintained at all times if possible.

Chemical Wellbore Cleaning Objectives

An equally critical aspect of a displacement is selection of an appropriate chemical cleanup sequence. A cleanup sequence is a series of specially-designed fluids (sometimes called “spacers”, “pills”, or “slugs”) that are pumped through the wellbore which are designed to clean the casing walls and other downhole tubulars while carrying debris to the surface. The chemical composition of the drilling fluid and of the completion fluid are the primary considerations when designing the spacers. Regardless of the fluid type, chemical wellbore cleaning objectives will include:

• Dispersion of gelled mud and mud solids
• Dissolution and removal of heavy hydrocarbons and pipe dope
• Ensuring that all downhole surfaces are left in a water-wet condition
• Filling the wellbore with a clean, solids-free completion fluid of the correct density and chemistry

The efficiency of wellbore cleanup chemicals on a specific mud should be tested in the lab prior to being run on a job. This is an opportunity to optimize the concentration of chemicals in each spacer.

Hydraulic Wellbore Cleaning Objectives

The final component of a displacement is hydraulic design. The chemical cleanup spacers will not work as designed if they are not pumped through the wellbore under the right conditions. Proper hydraulic design will achieve the following:

• All spacers (with the exception of Hi-Vis spacers) will be in a turbulent flow regime in all casing and liner sections
• Minimum annular velocity for all casing and liner sections will be 180 ft/min
• Total circulation time and waste volumes will be minimized – this means that the spacers should be as small as possible while still achieving the desired chemical cleaning effect
• Mixing along fluid interfaces will be minimized

An effective hydraulic displacement plan is dependent on a design that works within the limitations of the rig circulating equipment.

Wellbore Cleaning Chemicals

Utilizes two chemicals specifically for cleaning up the wellbore during displacements – an emulsified blend of water-soluble surfactant and fast acting solvent.

Water Based Mud Displacements

The chemical composition and volume of cleanup chemicals required for a water based mud displacement will be unique for each well. The order that they are pumped downhole, however, will generally be the same. Before designing the displacement, the following information must be known:

• Drilling mud density, rheology, and chemical composition
• Completion fluid density, rheology, and chemical composition
• Casing and liner sizes and depths
• Riser size and water depth (if it is an offshore well)
• Drill pipe size and total available length
• Rig pump limitations (maximum operating pressure and HHP)
• Bottomhole temperature

The rest of this section will detail the steps for designing the displacement for an example well. The well is as shown in the list below:

• 9.8 ppg water-bentonite-barite-lime mud, PV = 24 cP, YP = 28 #/100 ft²
• 9.5 ppg KCl brine, PV = 1.1 cP, YP = 0.1 #/100 ft²
• Vertical well, TD = 12,500 ft, 9.5/8” 53.5# casing shoe at 10,200 ft, 7” 29# liner from 10,200 ft to 12,500 ft
• Land well (no riser)
• 11,000 ft of 5”, 19.5#, S-135, 4.1/2 IF drill pipe, 3,000 ft of 3.1/2”, 13.3#, S-135, 3.1/2 IF drill pipe
• Maximum pump operating pressure = 4,500 psi, maximum pumping horsepower = 3,000 HHP
• BHT = 200 °F

Displacement Sequence

As previously mentioned, the order that the displacement spacers are pumped downhole will generally be the same for each well. The sequence is as follows:

1. Condition the drilling fluid
2. Hi-Vis transition spacer
3. Surfactant spacer
4. Caustic spacer
5. Hi-Vis tail spacer
6. Completion fluid

While being pumped down the drill pipe and up the annulus, they will be positioned relative to one another as shown in the photo below.

Once the displacement is complete, all of the spacers will be circulated out of the well and only completion fluid will remain.

Conditioning the Drilling Fluid

The first step in any displacement is conditioning the drilling fluid. Once we have run in hole with scrapers, brushes, magnets, etc. on drill pipe and the bit has reached bottom, the drilling fluid should be circulated through the well. As the drilling mud passes through the shale shakers and other solids control equipment at surface, some of the initial “cleaning” will take place as solid debris is removed. The viscosity of the mud should also be reduced as the solids concentration decreases. The minimum acceptable flow rate will be the rate that gives annular velocity of 180 ft/min in the largest annulus section. For this well, the minimum flow rate would be:

This is the minimum acceptable rate – we should actually increase the flow rate to the maximum possible without exceeding pump limits in order to maximize the cleaning efficiency. A hydraulics simulation would normally be required to find this rate, but for this example we will assume that the value is 450 gpm.

We must decide what volume of mud must be circulated before we can move on to the next step of the displacement. The “rule of thumb” for the volume to circulate while conditioning the drilling fluid is at least 150% of hole volume. This refers to the volume of fluid that would fill the casing and liner without any drill pipe in the hole. So for this well we would have:

Since the rule of thumb was that we needed to circulate at least 150% of hole volume, we need to multiply the figure above by 1.5.

In practice, it would be very difficult to pump exactly 1,210.4 bbl of drilling mud without going slightly over or under. To give ourselves a margin for error, we should instead plan to pump 1,250 bbl.

Hi-Vis Transition Spacer

The next fluid that will be pumped downhole is the Hi-Vis transition spacer. The purpose of this spacer is to displace the drilling fluid ahead of the rest of the cleanup fluids while lifting debris out of the wellbore. It acts like a “barrier” between the drilling fluid and subsequent cleanup fluids and pushes the vast majority of the mud out of the hole. The efficiency of the transition spacer is the most critical portion of the displacement.

Ideally, the transition spacer will provide a smooth change from mud to water-based cleaning spacers and avoid viscosity “spikes” associated with dehydration of water-based muds and formation of emulsions in oil-based muds.

The total volume of the transition spacer should be at least 10% of the hole volume. This is so it provides a sufficiently large barrier to displace the mud. An effective transition spacer will also will have a greater PV and YP than the drilling mud (to minimize mixing along the interface and improve solids carrying capacity) be at least 1.0 ppg denser than the drilling mud (to reduce pump pressure requirements and prevent mud settling through the spacer). If the drilling mud has a very low viscosity, a PV of at least 25 cP should be targeted.

Since we already calculated the hole volume in the previous step, it is simple to find the correct volume for the transition spacer.

Again, it would be difficult to pump precisely 80.7 bbl, so we will increase the volume slightly to give a margin for error.

Next, we need to increase the PV and YP of the transition spacer so that it is greater than the drilling mud. This is accomplished by adding polymers (xanthan gum or HEC) to the mixture. The amount of polymer required is dependent on the type of drilling mud, but a good rule of thumb is 2.5 – 4.0 pounds of polymer per barrel of transition spacer. Lab testing is required to optimize the concentration. In this case, we will assume that 3.0 pounds per barrel (ppb) of polymer will be sufficient. Therefore, the total polymer needed will be:

Polymer usually comes in 50 lb sacks, so we would actually need 6 sacks of polymer total.

Finally, we must ensure that we mix the transition spacer in such a way that it is 1.0 ppg heavier than the drilling mud. Ideally it should be solids-free since our goal is to remove solids from the wellbore rather than add them in. This means that one option is to use weighted brine as a base fluid. We have to be very cautious with this approach, however, since brine and mud mixtures can easily form emulsions or high viscosity “sludge”. If we are certain that there are no incompatibilities between the brine and mud we can use this method, but the safer route is to use drill water as the base fluid and increase the density using barite. The polymer that we added to increase the PV and YP will also increase the density slightly, and this will be taken into account at the end of the calculation.

We can use the equation below to find the amount of water needed to make 1 bbl of transition spacer.

In this case, we will design the transition spacer to be 1.5 ppg heavier than the drilling mud (9.8 ppg + 1.5 ppg = 11.3 ppg). We will also assume that barite has a density of 35 ppg and water has a density of 8.33 ppg.

So for every 1 bbl of transition spacer, we will need 0.889 bbl of water. Therefore, the total water required is:

The amount of barite needed for each barrel of transition spacer can now be calculated. The equation is as follows:

The final step is to calculate the total amount of barite required.

In summary, we would need the following materials to mix 85 bbl of the transition spacer:

• 75.6 bbl of water
• 13,617 lb of barite
• 255 lb of polymer

The same flow rate as used when conditioning the drilling fluid (450 gpm) will be used to pump this spacer.

Surfactant Spacer

Following the transition spacer, we will pump a surfactant spacer to wash the casing walls and other downhole tubulars and remove any remaining mud film. It will also “water-wet” the downhole surfaces and prepare the well for completion. The spacer will be primarily drill water or sea water with a small concentration of the chemical surfactant. The criteria for an effective surfactant spacer are a minimum 8 of minutes contact time with downhole tubulars, turbulent flow regime in all annulus sections, and optimized surfactant concentration

So the first thing we must decide is what volume of surfactant spacer is needed in order to achieve 8 minutes of contact time with all downhole tubulars. At first, it may seem as though the contact time depends on which section of the well the fluid is in. This is not true; the only factors that affect contact time are the total volume of the spacer and the flow rate. This is because the change in annular velocity (AV) as the spacer passes from one annulus section to another is exactly offset by the change in the height of the fluid column. Therefore, the equation to find contact time is:

Rearranging the equation to solve for the spacer volume and using the same flow rate as the previous spacers gives:

We will increase the volume of the spacer slightly to account for mixing along interfaces:

The next requirement is to ensure that the spacer is in a turbulent flow regime in all annulus sections. Unlike contact time, this is dependent on the casing and drill pipe size so we should examine the largest annulus section. If turbulence is maintained here, then we can be certain that it is also maintained in the other annulus section.

The easiest way to check for turbulence is to simulate the displacement in a hydraulics program that shows the flow regime. If a suitable program is not available, we can check for turbulent flow by calculating the Reynolds number of the spacer and comparing it to the Reynold’s number where the flow regime changes from laminar to turbulent (sometimes called the “critical Reynolds number”). The equation for Reynolds number in the annulus is:

The flow rate is still 450 gpm and the largest annulus is inside the 9.5/8” (ID = 8.535”) casing where we will use 5” drill pipe, so the average fluid velocity is:

With a PV of 1 cP and a YP of 0.1 lb/100 ft²we get an equivalent viscosity of:

This yields a Reynolds number of:

Turbulent flow occurs when N_Re > 2,100. Since our Reynolds number is significantly higher than this value, it is clear that the surfactant spacer will be in a turbulent flow regime in all annulus sections.

The final step is to decide what concentration of surfactant should be used, i.e. how much surfactant needs to be added into the water. The only way to know the required concentration with certainty is to get a sample of drilling mud and test different concentrations of surfactant to see which one most effectively cleans the mud off of the rotor of a Fann viscometer. Unfortunately, it’s usually not possible to get a sample of mud while planning the displacement (which might take place weeks or months before the well is drilled) so we have to use a “rule of thumb”. Water-based muds are generally easier to clean than oil-based muds so a 5-10% concentration of chemical surfactant is generally sufficient. For this example, we will use 5% surfactant concentration.

Therefore, we would need the following to mix the surfactant spacer:

The surfactant will be shipped in 55 gallon drums, so 4 drums would be needed.

Caustic Spacer

After the surfactant spacer, a caustic spacer will be pumped through the wellbore. Caustic soda (NaOH) is a highly alkaline substance that is often used as a degreaser and cleaner of manufacturing equipment. It will serve a similar function in the displacement process by dissolving any remaining hydrocarbon residues and cleaning the water-wet metal surfaces. It also neutralizes acids to prevent corrosion of downhole tubulars.

The guidelines for mixing a caustic spacer are very simple. The “rule of thumb” for most wells is that it should be 50 bbl, although for wellbores in excess of 1,000 bbl, 5% of total wellbore volume is a good guideline. It should be mixed in water with enough caustic soda added to achieve a pH of 12. In general, this will be 3.0 – 5.0 pounds of caustic soda per barrel of water. We also want to maintain turbulent flow in all annulus sections but as long as the surfactant spacer is in turbulent flow, we can be confident that the caustic spacer will be also since they have very similar viscosity and density.

So for the example well, we will mix 50 bbl of caustic spacer (since the well volume is less than 1,000 bbl). We will then add 4.0 ppb of caustic soda. Therefore, we will need 200 pounds of caustic soda.

Hi-Vis Tail Spacer

The last spacer pumped through the wellbore before the completion fluid is the Hi-Vis tail spacer. It acts like a final sweep through the well to catch any remaining solid debris that hasn’t already been circulated out. More importantly, it creates a barrier between the displacement spacers and the completion fluid that will be pumped into the well next. It is critical that the completion fluid is not allowed to mix with any other fluids since it might become contaminated.

The Hi-Vis tail spacer should use the completion fluid (brine) as a base fluid. The reason we do this instead of using fresh water like the other spacers is because fresh water could dilute the completion fluid

at the interface between them. This would change the brine density and possibly alter its chemical and physical properties.

The Hi-Vis tail spacer is generally 50 bbl,although for wells with a volume greater than 1,000 bbl we should instead use 5% of the total well volume as a guideline. In addition, it must have a YP of at least 15 #/100 ft². This is accomplished by adding 2.0 – 4.0 ppb of xanthan gum or HEC to the base fluid. It will be difficult to achieve a high viscosity since it is solids-free.

Since the example well is less than 1,000 bbl, we will use a 50 bbl Hi-Vis tail spacer. If we use 3.0 ppb of polymer to achieve a YP of 15 #/100 ft², we’ll need 150 pounds of polymer total.

Completion Fluid

The completion fluid should be pumped into the wellbore after all of the displacement spacers. The type of completion fluid will be based decided by the operator on the well conditions. We must, of course, pump enough fluid to fill the entire wellbore. We should actually prepare excess completion fluid, though, to account for mixing along interfaces and surface contamination. A good “rule of thumb” is to prepare 150 bbl of excess completion fluid if possible. That means we would need 150 bbl on top of the 807 bbl of volume in the example well – 957 bbl total. The completion fluid should be pumped at the maximum rate possible.

Most operators will want to continue circulating the completion fluid through the well until it meets the desired level of cleanliness. Cleanliness is measured in two ways: turbidity, which is a measure of how clear the fluid is, and total suspended solids, which is the percentage of whole fluid that is made up of solid particles. Samples of fluid will be taken as they exit the well and tested to see if they meet the standards.

Summary

The key to a successful displacement from water-based mud to completion fluid is proper planning. The potential for fluid incompatibilities and formation damage means that it is a critical stage in well construction. Factors that must be addressed before each job are:

• Pump rate
• Annular velocity and contact time
• Fluid density
• Fluid viscosity
• Chemical composition and concentration
• Pit limitations
• Pump limitations

As always, the mechanical wellbore cleaning tools must be combined with chemicals and hydraulics to achieve an efficient displacement.

Oil-Based Mud Displacements

The chemical composition and volume of cleanup chemicals required for a water based mud displacement will be unique for each well. The order that they are pumped downhole, however, will generally be the same. Before designing the displacement, the following information must be known:

• Drilling mud density, rheology, and chemical composition
• Completion fluid density, rheology, and chemical composition
• Casing and liner sizes and depths
• Riser size and water depth (if it is an offshore well)
• Drill pipe size and total available length
• Rig pump limitations (maximum operating pressure and HHP)
• Bottomhole temperature

The rest of this section will detail the steps for designing the displacement for an example well. The well is as shown in the list below:

• 10.5 ppg oil-based mud, PV = 27 cP, YP = 20 #/100 ft²
• 10.0 ppg CaCl₂ brine, PV = 1.1 cP, YP = 0.1 #/100 ft²
• Vertical well, TD = 13,850 ft, 9.7/8” 62.8# casing shoe at 9,600 ft, 7.5/8” 39# liner from 9,600 ft to 13,850 ft
• Land well (no riser)
• 10,000 ft of 5.5”, 24.7#, S-135, 5.1/2 FH drill pipe, 5,000 ft of 3.1/2”, 13.3#, S-135, 3.1/2 IF drill pipe
• Maximum pump operating pressure = 4,500 psi, maximum pumping horsepower = 3,000 HHP
• BHT = 200 °F

Displacing an oil-based mud from the wellbore is generally more difficult than displacing a water-based mud. The sequence of spacers for displacing an oil-based mud to a solids-free completion fluid is as follows:

1. Condition the drilling fluid
2. Base oil spacer
3. Hi-Vis transition spacer
4. Solvent spacer
5. Surfactant spacer
6. Hi-Vis tail spacer
7. Completion fluid

When pumped down the drill pipe and up the annulus, they will be positioned relative to one another as shown in the photo below.

Once the displacement is complete, all of the spacers will be circulated out of the well and only completion fluid will remain.

Conditioning the Drilling Fluid

The first step in any displacement is conditioning the drilling fluid. Once we have run in hole with scrapers, brushes, magnets, etc. on drill pipe and the bit has reached bottom, the drilling fluid should be circulated through the well. As the drilling mud passes through the shale shakers and other solids control equipment at surface, some of the initial “cleaning” will take place as solid debris is removed. The viscosity of the mud should also be reduced as the solids concentration decreases. The minimum acceptable flow rate will be the rate that gives annular velocity of 180 ft/min in the largest annulus section. For this well, the minimum flow rate would be:

This is the minimum acceptable rate – we should actually increase the flow rate to the maximum possible without exceeding pump limits in order to maximize the cleaning efficiency. A hydraulics simulation would normally be required to find this rate, but for this example we will assume that the value is 400 gpm.

We must decide what volume of mud must be circulated before we can move on to the next step of the displacement. The “rule of thumb” for the volume to circulate while conditioning the drilling fluid is at least 150% of hole volume. This refers to the volume of fluid that would fill the casing and liner without any drill pipe in the hole. So for this well we would have:

Since the rule of thumb was that we needed to circulate at least 150% of hole volume, we need to multiply the figure above by 1.5.

In practice, it would be very difficult to pump exactly 1,311.8 bbl of drilling mud without going slightly over or under. To give ourselves a margin for error, we should instead plan to pump 1,350 bbl.

Base Oil Spacer

After the drilling mud has been conditioned and the PV and YP have reached acceptable levels, a base oil spacer should be pumped into the well. This is simply the base fluid used to mix the oil-based mud.

The reason we pump a base oil spacer is to thin and disperse pockets of gelled oil-based mud. Mud solids can settle out and accumulate along the low side of the hole in deviated sections and become very viscous. By pumping in base oil, we effectively break up these areas of viscous mud so they can be circulated out of the well.

Base oil can be quite expensive, so we would like to minimize the amount that needs to be used. 50 bbl is generally sufficient to accomplish the goals mentioned above.

We will use the same pump rate as used when conditioning the drilling fluid. The base oil spacer will be:

Hi-Vis Transition Spacer

The next fluid that will be pumped downhole is the Hi-Vis transition spacer. The purpose of this spacer is to displace the drilling fluid ahead of the rest of the cleanup fluids while lifting debris out of the wellbore. It acts like a “barrier” between the drilling fluid and subsequent cleanup fluids and pushes the vast majority of the mud out of the hole. The efficiency of the transition spacer is the most critical portion of the displacement.

Ideally, the transition spacer will provide a smooth change from mud to water-based cleaning spacers and avoid viscosity “spikes” associated with dehydration of water-based muds and formation of emulsions in oil-based muds.

The total volume of the transition spacer should be at least 10% of the hole volume. This is so it provides a sufficiently large barrier to displace the mud. It also must contain a small concentration of solvent and surfactant to begin the chemical cleaning process. An effective transition spacer will also will have a greater PV and YP than the drilling mud (to minimize mixing along the interface and improve solids carrying capacity) be at least 1.0 ppg denser than the drilling mud (to reduce pump pressure requirements and prevent mud settling through the spacer). If the drilling mud has a very low viscosity, a PV of at least 25 cP should be targeted.

Since we already calculated the hole volume for this well, it is simple to find the correct volume for the transition spacer.

It would be difficult to pump precisely 131.2 bbl, so we will increase the volume slightly to give a margin for error.

A solvent and a surfactant should also be added to the transition spacer when displacing an oil-based mud. The exact concentration of chemicals required depends on the well conditions and requires lab testing to establish. However, a good guideline is that the surfactant concentration should be 3-5 % by volume and the solvent concentration should be twice that (6-10 % by volume). We will use 4% surfactant and 8% solvent for this well. This means that we need the following amount of chemicals:

Both of these chemicals come in 55 gallon drums, so we would need 5 drums of chemical surfactant and 9 drums of solvent.

Next, we need to increase the PV and YP of the transition spacer so that it is greater than the drilling mud. This is accomplished by adding polymers (xanthan gum or HEC) to the mixture. The amount of polymer required is dependent on the type of drilling mud, but a good rule of thumb is 2.5 – 4.0 pounds of polymer per barrel of transition spacer. Lab testing is required to optimize the concentration. In this case, we will assume that 3.0 pounds per barrel (ppb) of polymer will be sufficient. Therefore, the total polymer needed will be:

Polymer usually comes in 50 lb sacks, so we would actually need 9 sacks of polymer total.

Finally, we must ensure that we mix the transition spacer in such a way that it is 1.5 ppg heavier than the drilling mud. Ideally it should be solids-free since our goal is to remove solids from the wellbore rather than add them in. This means that one option is to use weighted brine as a base fluid. We have to be very cautious with this approach, however, since brine-mud mixtures can easily form emulsions or high viscosity “sludge”. If we are certain that there are no incompatibilities between the brine and mud we can use this method, but the safer route is to use drill water as the base fluid and increase the density using barite. The polymer that we added to increase the PV and YP will also increase the density slightly, and this will be taken into account at the end of the calculation.

We can use the equation below to find the amount of water needed to make 1 bbl of transition spacer.

In this case, we will design the transition spacer to be 1.5 ppg heavier than the drilling mud (10.5 ppg + 1.5 ppg = 12.0 ppg). Given chemical surfactant has a density of 7.5 ppg and solvent has a density of 6.8 ppg. We will also assume that barite has a density of 35 ppg and water has a density of 8.33 ppg.

So for every 1 bbl of transition spacer, we will need 0.8737 bbl of water. Therefore, the total water required is:

The amount of barite needed for each barrel of transition spacer can now be calculated. The equation is as follows:

The final step is to calculate the total amount of barite required.

In summary, we would need the following materials to mix 85 bbl of the transition spacer:

• 99.5 bbl of water
• 226.8 gal of emulsified blend of water-soluble surfactant
• 453.6 gal of blend of fast-acting solvent
• 51,787 lb of barite
• 405 lb of polymer

The same flow rate as used when conditioning the drilling fluid (400 gpm) will be used to pump this spacer.

Solvent Spacer

The next spacer to be pumped downhole will be the solvent spacer. It is designed to dissolve heavy hydrocarbons and pipe dope as well as thin the oil residue from the oil-based mud. This is an important step since the casing and other downhole tubulars will be oil-wet. The solvent spacer will be primarily made up of water with a small concentration of solvent.

The guidelines for a successful solvent spacer are a minimum of 8 minutes contact time with downhole tubulars, turbulent flow regime in all annulus sections, and optimized solvent concentration.

So the first thing we must decide is what volume of surfactant spacer is needed in order to achieve 8 minutes of contact time with all downhole tubulars. At first, it may seem as though the contact time depends on which section of the well the fluid is in. This is not true; the only factors that affect contact time are the total volume of the spacer and the flow rate. This is because the change in annular velocity (AV) as the spacer passes from one annulus section to another is exactly offset by the change in the height of the fluid column. Therefore, the equation to find contact time is:

Rearranging the equation to solve for the spacer volume and using the same flow rate as the previous spacers gives:

We will increase the volume of the spacer slightly to account for mixing along interfaces:

The next requirement is to ensure that the spacer is in a turbulent flow regime in all annulus sections. Unlike contact time, this is dependent on the casing and drill pipe size so we should examine the largest annulus section. If turbulence is maintained here, then we can be certain that it is also maintained in the other annulus section.

The easiest way to check for turbulence is to simulate the displacement in a hydraulics program that shows the flow regime. If a suitable program is not available, we can check for turbulent flow by calculating the Reynolds number of the spacer and comparing it to the Reynold’s number where the flow regime changes from laminar to turbulent (sometimes called the “critical Reynolds number”). The equation for Reynolds number in the annulus is:

The flow rate is still 400 gpm and the largest annulus is inside the 9.7/8” (ID = 8.562”) casing where we will use 5.5” drill pipe, so the average fluid velocity is:

With a PV of 1 cP and a YP of 0.1 lb/100 ft² we get an equivalent viscosity of:

This yields a Reynolds number of:

Turbulent flow occurs when N_Re > 2,100. Since our Reynolds number is significantly higher than this value, it is clear that the solvent spacer will be in a turbulent flow regime in all annulus sections.

The final step is to decide what concentration of solvent should be used, i.e. how much solvent needs to be added into the water. The only way to know the required concentration with certainty is to get a sample

of drilling mud and test different concentrations of solvent to see which one most effectively dissolves oil residue on the rotor of a Fann viscometer. Unfortunately, it’s usually not possible to get a sample of mud while planning the displacement (which might take place weeks or months before the well is drilled) so we have to use a “rule of thumb”. solvent concentration should be 5-15% by volume with a higher concentration needed for dense muds. Since our mud is relatively light (10.5 ppg) we will use a concentration of 10% by volume.

Therefore, we would need the following to mix the solvent spacer:

The solvent will be shipped in 55 gallon drums, so 7 drums would be needed.

Surfactant Spacer

The surfactant spacer will be pumped downhole next. It is critical that the spacers are pumped in this order since we want to leave the casing water-wet. If the surfactant spacer was pumped first and then followed by the solvent spacer, the casing would be left oil-wet.

The criteria for an effective surfactant spacer are very similar to the solvent spacer. We require at least 8 minutes contact time with downhole tubulars, turbulent flow in all annulus sections, and optimized surfactant concentration. The surfactant spacer will be primarily composed of water with no additives other than the chemical surfactant.

The first thing we must do is decide how large the spacer needs to be. We use the same method for calculating contact time as with previous spacers.

Rearranging the equation to solve for the spacer volume and using the same flow rate as the previous spacers gives:

We will increase the volume of the spacer slightly to account for mixing along interfaces:

The method for determining whether the surfactant spacer is in turbulent flow is also the same as with the solvent spacer. We will not go through the calculation again in this section, so refer back to the previous section for the steps. The surfactant spacer will be in turbulent flow at 400 gpm.

Finally, we must optimize the concentration of surfactant in the spacer. It is mixed into water at a concentration of 10 – 15% by volume for surfactant spacers in oil-based mud displacements. Lab testing is required to determine the best concentration, but in general, a higher concentration of surfactant is required for dense oil-based muds than less-dense muds. Since we are using a relatively low density mud, a surfactant concentration of 12% by volume will suffice. This means we need:

Hi-Vis Tail Spacer

The last spacer pumped through the wellbore before the completion fluid is the Hi-Vis tail spacer. It acts like a final sweep through the well to catch any remaining solid debris that hasn’t already been circulated out of the well. More importantly, it creates a barrier between the displacement spacers and the completion fluid that will be pumped into the well next. It is critical that the completion fluid is not allowed to mix with any other fluids since it might become contaminated.

The Hi-Vis tail spacer should use the completion fluid (brine) as a base fluid. The reason we do this instead of using fresh water like the other spacers is because fresh water could dilute the completion fluid

at the interface between them. This would change the brine density and possibly alter its chemical and physical properties.

The Hi-Vis tail spacer is generally 50 bbl,although for wells with a volume greater than 1,000 bbl we should instead use 5% of the total well volume as a guideline. In addition, it must have a YP of at least 15 #/100 ft². This is accomplished by adding 2.0 – 4.0 ppb of xanthan gum or HEC to the base fluid. It will be difficult to achieve a high viscosity since it is solids-free.

Since the example well is less than 1,000 bbl, we will use a 50 bbl Hi-Vis tail spacer. If we use 3.0 ppb of polymer to achieve a YP of 15 #/100 ft², we’ll need 150 pounds of polymer total.

Completion Fluid

The completion fluid should be pumped into the wellbore after all of the displacement spacers. The type of completion fluid will be based decided by the operator on the well conditions. We must, of course, pump enough fluid to fill the entire wellbore. We should actually prepare excess completion fluid, though, to account for mixing along interfaces and surface contamination. A good “rule of thumb” is to prepare 150 bbl of excess completion fluid if possible. That means we would need 150 bbl on top of the 1,210 bbl of volume in the example well – 1,360 bbl total. The completion fluid should be pumped at the maximum rate possible.

Most operators will want to continue circulating the completion fluid through the well until it meets the desired level of cleanliness. Cleanliness is measured in two ways: turbidity, which is a measure of how clear the fluid is, and total suspended solids, which is the percentage of whole fluid that is made up of solid particles. Samples of fluid will be taken as they exit the well and tested to see if they meet the standards.

Summary

The key to a successful displacement from water-based mud to completion fluid is proper planning. The potential for fluid incompatibilities and formation damage means that it is a critical stage in well construction. Factors that must be addressed before each job are:

• Pump rate
• Annular velocity and contact time
• Fluid density
• Fluid viscosity
• Chemical composition and concentration
• Pit limitations
• Pump limitations

As always, the mechanical wellbore cleaning tools must be combined with chemicals and hydraulics to achieve an efficient displacement.

Special Cases

Direct vs. Indirect Displacements

When drilling offshore wells, some operators prefer to displace the well to seawater before pumping in the completion fluid – this is called an “indirect” displacement. “Direct” displacements, where we go directly from drilling mud to completion fluid, have already been discussed. For water-based mud indirect displacements, the spacer sequence would be:

1. Circulate/condition drilling fluid
2. Hi-Vis transition spacer
3. Surfactant spacer
4. Caustic spacer
5. Hi-Vis tail spacer (viscosified seawater)
6. Seawater
7. Hi-Vis tail spacer (viscosified completion fluid)
8. Completion fluid

For oil-based mud indirect displacements, the sequence would be:

1. Circulate/condition drilling fluid
2. Hi-Vis transition spacer
3. Solvent spacer
4. Surfactant spacer
5. Hi-Vis tail spacer (viscosified seawater)
6. Seawater
7. Hi-Vis tail spacer (viscosified completion fluid)
8. Completion fluid

At least one complete circulation of seawater should be performed at the maximum possible pump rate before proceeding to the completion fluid (so if the total well volume is 850 bbl, we should pump at least an equal volume of seawater). This will flush any remaining debris from the wellbore and remove contaminants that could damage the completion fluid. It also serves as a very large barrier between the displacement spacers and the completion fluid.

The Hi-Vis tail spacer (viscosified seawater) should use the same guidelines as the Hi-Vis tail spacer for water-based and oil-based mud displacements except that it will use seawater as the base fluid. Refer back to the previous sections for more details.

The downsides to indirect displacements are that it takes additional rig time (and therefore costs more) and that it causes a large reduction in bottomhole pressure. When the drilling fluid is displaced to seawater, which weighs approximately 8.50 ppg, the hydrostatic pressure at the bottom of well might drop by 1,000 psi or more. This could be unacceptable on a well utilizing an open hole completion since it would cause a kick. It is also risky for cased holes that have not been pressure tested.

The decision to use an indirect displacement instead of a direct displacement should be made by the well operator.

Negative Pressure Testing of Liner Tops

When we displace the well from mud to completion fluid, we lower the bottomhole pressure, since the mud is denser than the completion fluid in most cases. This means that we are increasing the risk of taking a kick when we displace the well.

Because of this risk, it is common to perform a negative pressure test (sometimes called an “inflow test”). This involves setting a packer pumping a light fluid down the drill string (water for water-based muds or base oil for oil-based muds). Once the light fluid is inside the drill string, standpipe pressure is bled off at surface. This lowers the bottomhole pressure to simulate the pressure once the displacement is complete. If there is no increase in pressure or flow at surface we can be confident that the well is secure and it is safe to displace to completion fluid.

Negative pressure tests are legally required before displacements in certain parts of the world.

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