The term, displacement, as it pertains to the transition from drilling to completion operations, has come to encompass the entire process of removing the solid laden drilling fluid and replacing it with a solid free completion fluid. In reality, there are three separate processes involved in a successful displacement:
- removal of the bulk of the drilling fluid from the wellbore,
- wellbore cleanup during which the remainder of the drilling fluid residue is removed, and
- installation of the solid free completion fluid.
An efficient displacement completely removes the mud from the wellbore, maintains the integrity of both the brine and the mud, establishes a solid free environment, and minimizes filtration time. All of these criteria must be met in the most cost efficient manner.
|It is imperative that incompatible fluids always be separated.
Heavy brines are incompatible with water based and oil based muds. This incompatibility can produce a viscous, unpumpable mass due to flocculation of the mud by high salt content of the brines. Should this reaction take place downhole during the displacement, the friction pressures will increase dramatically. As additional commingling takes place, a point may be reached where pumping operations have to be suspended due to excessive downhole casing, tubing, or pump pressures. The contamination of completion fluids by solid laden drilling fluids can result in the inability to process the fluid through filtration equipment, making it impossible to maintain the required solid free environment.
Generally, there are two techniques available to achieve a successful displacement. These methods are referred to as indirect displacement and direct displacement.
Indirect Displacement. The indirect displacement method displaces the mud using water. Seawater is circulated downhole one time and is discarded upon its return to the surface. This rinsing process continues until drilling mud residue in the returns is minimal. At this point, one or more chemical sweeps are circulated through the hole. These sweeps are designed to dislodge any drilling mud that remains on the surfaces of the wellbore. Once this residue has been dislodged from the surfaces, viscous fluid is circulated through the wellbore to aid in its removal from the well. Indirect displacements yield good results at low cost. However, several factors can limit their application, including:
- an inadequate supply of available water,
- an inability to discharge water due to environmental regulations (zero discharge),
- discharge volume limitations,
- environmental contaminant levels,
- pressure and integrity considerations, and
- rig time cost.
Direct Displacement. A direct displacement differs from an indirect displacement in that it accomplishes all three displacement processes in one circulation or sequence. In effect, you are able to go directly from the drilling fluid, into the cleanup system, and then into the completion fluid without the interruption of a rinsing process, which can be time consuming. Some of the benefits of a direct displacement are: minimizing rig time spent in pumping, reducing generated waste, and maintaining required wellbore pressures.
There are five major points to consider prior to conducting direct displacement operations:
- chemical displacement system design,
- condition of surface equipment,
- predisplacement condition of mud,
- condition of flow path, and
- pressure differentials.
Chemical Displacement Systems
TETRA’s highly engineered chemical displacement systems are designed to disperse solids and water wet all metal surfaces. Components of the system can be designed for indirect or direct displacement of water based, diesel oil based, and synthetic oil based muds.
TDSP Displacement System
The TDSP spacer system requires the pumping of a minimum of three spacers. Each spacer is specifically designed by your TETRA fluids specialist to perform one of the three displacement processes and maintain compatibility with the fluids it contacts.
TETRA developed this multistage system to separate the drilling fluid from the brine. The system consists of the TDSP I weighted spacer, the TDSP II surfactant wash, and the TDSP III viscosified sweep. The overriding design consideration for this system is to maintain compatibility of all fluids which contact each other.
TDSP I. The mud displacement stage, TDSP I is a weighted spacer designed to act as a piston within the wellbore to push the drilling fluid ahead of it. A TDSP I weighted spacer relies on yield point, gel strength, density, and apparent viscosity to maintain its integrity as it travels through the wellbore. By acting as a piston, the TDSP I pill effectively prevents the channeling of fluids.
TDSP II. The surfactant wash stage, TDSP II is a turbulent flow spacer with concentrated surfactants that is specifically designed for the mud type. This stage works to disperse any residual mud from the tubular surfaces. The TDSP II spacer is designed to provide a minimum of 2,000 feet of coverage and a minimum of 10 minutes contact time in the largest annular section of the wellbore. While maximum pumping rates are often limited by pump capabilities, an annular velocity of 180 ft/min is recommended in each annular interval.
Another essential design factor in the TDSP II spacer is to ensure that sufficient TDSP II is available to incorporate the entire volume of anticipated drilling mud residue that may be present. In some cases, this consideration overrides the annular coverage and contact time recommendations mentioned above. This consideration requires extensive testing of the TDSP II spacer for its maximum residue capacity. It is always desirable to perform these tests on a sample of the mud from the wellbore for which which you are planning the displacement.
TDSP III. The viscosified sweep stage, TDSP III is the spacer used between the surfactant wash spacer and the CBF. This stage is designed to remove any residual materials that are dispersed by the surfactant wash and to provide warning of the returning brine. This warning allows time for personnel to divert returns once the spacer system has been circulated out of the well. Like TDSP I, TDSP III should exhibit rheological properties that allow it to maintain its integrity while traveling through the wellbore. This integrity is essential in minimizing the commingling of the TDSP III and the CBF. Individual stage volumes shown in Table 51 are designed with three goals in mind:
- to allow physical separation to protect brine from mud contamination,
- to provide sufficient contact time for efficient cleaning of the wellbore, and
- to carry residual solids out of the wellbore.
TABLE 51. TDSP Displacement System
|Guidelines for Individual Spacer Stage Annular Coverage
||Contact Time (min)
TETRAClean Displacement System
Environmental regulations in some oil and gas provinces, such as the North Sea, may suggest the TETRAClean™ displacement system. This alternative product has found wide acceptance because:
- it is a one pill-one pit system that conserves scarce pit capacity on offshore platforms,
- it consists of components that have earned a Gold designation in accordance with Chemical Hazard Assessment and Risk Management (CHARM) regulations promulgated by the OSPAR Commission for the Protection of the Marine Environment of the North-East Atlantic, and
- the recommended higher annular velocity used in TETRAClean displacements results in a much shorter displacement time.
One Pill–One Pit. As pit volume is a scarce commodity on any offshore platform, the TETRAClean displacement system was designed around the concept of one pill-one pit. The TETRAClean displacement pill is typically made up in the range of 200 to 250 bbl. In actual practice, the volume is designed around achieving a contact time of 10 minutes. For maximum benefits, a minimum annular velocity of 250 ft/min is recommended (if practiceable) to promote the scouring and suspending action associated with highly turbulent flow. This higher annular velocity has the added benefit of shortening the time of displacement operations.
In monovalent brines, such as those based on sodium or potassium salts, the TETRAClean pill is mixed in a volume of working brine that has been viscosified with TETRA BioPol viscosifier. A yield point of more than 50 lb/100ft2 is recommended for the viscosified pill. The two active components are TETRAClean 105 surfactant and TETRAClean 106 activator.
In calcium based fluids, TETRAVis L HEC viscosifier is the preferred viscosifying agent. In those cases, TETRAClean 105 surfactant is used alone, but at a higher dosage rate because of the chelating tendency of TETRAClean 106 activator toward divalent ions.
Environmentally Friendly. Offshore oil and gas activities in the North Sea are guided by stringent environmental regulations. Under the internationally recognized OSPAR Commission, all chemicals used must comply with standards set under the CHARM program. TETRAClean 105 surfactant has earned a Gold designation under this classification system. TETRAClean 106 activator has been shown to “present little or no risk” (PLONOR) of environmental damage.
General Applications. The TETRAClean one pill displacement system can be run after water based, diesel oil based, or synthetic oil based drilling fluids, provided a compatible spacer is run between the mud and the TETRAClean pill. Recommended practice for the TETRAClean pill involves circulating down the working string. Wells with large or abrupt changes in diameter may require special attention to ensure that mud residue is not left on the shoulder of the liner top. Additional cleaning action may be accomplished with a bypass circulating tool (e.g., TETRA’s Selective Rotation Circulating Tool) to ensure there is adequate fluid circulation at the liner top.
The principles of good displacement outlined in the following sections are equally important when using either of TETRA’s chemical displacement systems.
Displacement Modeling Software
When planning displacement operations for our customers, TETRA uses modeling software to determine product applications and whether high pressure pumping equipment may be required. The software programs and their uses are explained below.
CV-Pro™ circulating volume and displacement modeling software is used to calculate well volumes and displacement data (i.e., spacer volumes, spacer coverage, and spacer contact time as a function of pump rate), which are values used in well displacements. The program also calculates surface area, individual well capacity, and annular velocities. The CV-Pro program is also useful in providing information necessary for spotting balanced plugs or pills. Additionally, the program is a useful tool when planning the minimum pill volume and the necessary pump rate for optimal displacement spacer performance.
DIS-Pro™ hydraulic modeling software is used to model a specific displacement operation and provide detailed information on anticipated pump pressures, hydraulic horsepower requirements, equivalent circulating densities, and other pressure calculations in a displacement timeline format. The program is designed to simulate all configurations of the wellbore, as well as forward and reverse fluid circulation options, bypass flow (downhole bypass circulating valves), and two stage openhole displacements at all given pump rates. The DIS-Pro program can also calculate a backpressure schedule to maintain a constant bottomhole pressure when necessary. The program will also identify freefall events and calculate downhole pressure losses. A DIS-Pro simulation is recommended to optimize and define appropriate displacement operation parameters.
Condition of Surface Equipment
Prior to the arrival of the brine at the rig site, personnel should be directed to check the cleanliness of the fluid handling tanks, flowlines, pump suction, manifolds, and gun lines. There should be no visible water, dirt, rust, or scale deposits. Pressure washers and surfactants should be employed to thoroughly clean all surfaces. The surfactant used should be chosen on the basis of being the most effective for the particular drilling mud involved.
It is also important to check for possible leaks at hose connections, dump valves, tank inspection plates, pumps, flowlines, and bell nipples. Some completion fluids are considered marine pollutants and must not be released into the environment. In these cases, all dump valves should be closed. Secondary sealing methods (for example, applying silicone sealer or welding the valves) are recommended. Valve handles should be locked out and tagged out to prevent inadvertent opening.
All active pits should be covered. Fully enclosed tanks are essential for spike fluid storage due to the hygroscopic nature of high density brines. Sources of water, such as hoses, drains, sinks, and water addition lines, should also be locked out and tagged out. Other sources, such as eye wash stations, should be checked regularly for leaks, and repairs should be made as they become necessary.
The condition of surface equipment must be given serious consideration. In many cases, the completion fluid system represents a substantial investment. Any preventative action which costs less than the value of the fluid system or the cost to remove contamination is always justified.
Predisplacement Condition of Mud
Prior to displacement operations, the drilling fluid should be circulated a minimum of one annular volume (bottoms up) and the properties checked. Regardless of the mud type, good rheological properties are of the utmost importance. In addition to optimum mud properties, recent movement of the mud is essential.
Oil based muds generally maintain good rheological properties and seldom present any problems. A good mud check after circulating one annular volume (bottoms up) is still recommended to verify acceptable rheological properties.
Condition of Flowpath
Mud mobility is essential to a successful displacement. Obviously, the first thing to do is to obtain circulation to the required depth. If the mud is in good condition, it may only be necessary to circulate several hole cycles to distribute the solids. In less than ideal circumstances, it may be necessary to wash through or even drill out settled solids. If at all possible, the mud should be circulated until the displacement begins. Cleaning rig pits prior to introducing completion fluids into them may take many hours. During this time, even the best muds may develop high gel strengths or barite settling may occur in the wellbore.
The most effective and least expensive method of removing mud solids from tubular goods is to use TETRA’s specially designed scraper and brush tools. While going in the hole, these tools physically disrupt the filter cake that forms in the wellbore. This mechanical removal eases the burden on the TDSP II surfactant sweep. After the completion fluid has been circulated into the wellbore, it is advisable to short trip (re-scrape) the wellbore to remove any residual mud materials. This step should then be followed by circulation and filtration of the completion fluid.
DIS-Pro hydraulic modeling software can be used by fluids specialists to analyze displacement hydraulics so that pressure differentials can be minimized through proper adjustment of individual spacer densities and/or rheology. Minimizing excessive pressure differentials is important, as they can interrupt pumping due to elevated pump pressures or tubular strength limitations.
Another point regarding pressure differentials relates to displacing a light fluid with a heavier fluid. As the fluid enters the wellbore, the heavier fluid may force the lighter fluid from the hole more rapidly than good judgment would dictate. This u-tube effect should be controlled by maintaining back pressure with the choke. If this is not done, interfacial losses tend to be high due to poor fluid hydraulics. This situation often results in density loss as well. Fluid economics aside, safety is compromised any time the wellbore is not under control.
Factors Influencing Displacement Efficiency
The rheology of the mud and the spacer system is a major factor affecting displacement efficiency. Consider the behavior of a fluid flowing through a pipe. If the velocity of the fluid is very low, individual particles of fluid tend to move in straight lines parallel to the direction of flow. The flowing fluid consists of very thin, cylindrical layers of fluid concentric with the tubing walls. These layers, or lamina, give rise to the term laminar flow.
The particles of fluid in an individual layer move at the same velocity. However, the different layers will ordinarily move at different velocities. Theoretically, the layer next to the wall is stationary, layers close to the wall move slowly, while those close to the center move more rapidly. If you think of the layers as sliding by one another, the relative velocity between two adjacent layers is known as the shear rate.
Fluid tends to resist having its individual layers move at different speeds. The resistive force that a layer offers to prevent nearby layers from sliding by is called the shear stress. At higher velocities, fluid is not ordinarily in laminar flow. Instead, individual particles tend to bounce and tumble along in an almost random way. This type of flow is called turbulent flow.
When very low velocities are combined with relatively high viscosities, a situation occurs whereby the fluid flow almost resembles a solid. Particles tend to remain relatively stationary with respect to one another, and the fluid travels down the tubing as an almost solid mass. This occurrence is called plug flow.
|The removal of solids from casing walls by scrubbing action is best accomplished by highly turbulent flow. High velocity is characterized by high turbulence and good scrubbing action. A velocity of 180 ft/min in the largest annular section of pipe is recommended.
In order for the various spacers in the TDSP system to work properly, it is imperative that the drilling fluid rheology be controlled. In simplistic terms, the yield point is a measure of the ability of a fluid to hold together under applied stress. Ideally, we reduce the yield point of the mud to the bare minimum that is required to support barite. If the yield point of the mud removal spacer is less than the yield point of the mud, then the spacer will channel through the mud and hole cleaning capability will be severely reduced.
Direction of Circulation
Another major factor affecting displacement efficiency is the direction or type of circulation employed. The densities of the brine and the fluid being displaced influence the flow path to be used. The lighter fluid should be above the heavier fluid in the annulus. Under static conditions, high density fluids tend to sink through low density fluids due to the effect of gravity. Because of this, even with spacers to separate incompatible fluids, intermingling and flocculation is possible.
Reverse circulation offers several advantages over standard circulation when conditions permit. The direction of the flow path is a primary factor in determining individual stage volumes. When reversing, higher fluid velocities in the tubing prevent solids from slipping back down the wellbore by maximizing the lifting capacity of the fluid. Therefore, less physical separation is required.
|Whenever possible, the lead spacer should be 0.5 lb/gal to 1.0 lb/gal heavier than the mud being displaced.
Wellbore eccentricity occurs when the working string passes through a section of cased hole that deviates from the vertical axis. Virtually all wellbores have some deviation; some of this deviation is intentional and some is not. The number of deviations and the severity of the individual deviations will greatly affect the displacement.
If a typical vertical wellbore profile is examined, where no individual deviation angle is greater than 3°, it is apparent that even with the small amount of vertical deviation, hundreds of feet of working string are in contact with the casing. The casing/working string interface causes static mud stringers that are extremely difficult to remove.
FIGURE 21. Wellbore Eccentricity
The degree of eccentricity in the annulus is defined by the term percent standoff. When the working string is perfectly centered in the wellbore, the percent standoff is 100%. If a working string creates an annulus with a one inch gap when centered and is then set off 0.5 inches from the casing wall, the resulting annulus has a 50% standoff. Percent standoff decreases as the eccentricity in the annulus increases. Percent standoff and displacement efficiency are directly related. As percent standoff decreases from 100% with all other parameters kept constant, the displacement efficiency decreases and larger spacers are required.
The ideal situation would be to centralize the working string, but this is not typically done in practice. Rotation of the working string is an effective alternative. By rotating slowly during the displacement, mud channels can be broken up and removed efficiently.
It is not uncommon to be unable to rotate the pipe when rigged up for reverse circulation. Reverse circulation requires either the Hydril® or pipe rams to be closed, and many operators are unwilling to subject the Hydril to any extra wear.
If the well design will allow setting 4,000 to 5,000 lb of weight on the bit, an alternative to pipe rotation is to pick up and slack off string weight. This action causes pipe movement, which aids in the removal of mud stringers.
Exaggerated pipe reciprocation should be avoided while introducing the brine. In addition to pressure fluctuations, there is a tendency for interface sizes to increase due to increased movement in the annulus. Reciprocation can be beneficial during predisplacement mud conditioning or while circulating seawater in the well. The physical motion of the pipe helps remove solids that are adhering to the tubular surfaces.
|It is important to remember that the pumps must not be shut down during the displacement operation. If the pumps are prematurely stopped, the displacement system may string out and cause a decrease in hole cleaning effectiveness. This could possibly lead to contamination of the brine with particulate solids.
When weighted spacer systems are designed to incorporate all downhole conditions and are engineered with all available technologies, overall well costs can be reduced. This reduction will be seen in reduced filtration requirements, reduced rig time associated with filtration, and in the reclamation of contaminated fluids.