Wellbore Clean-up

Chapter 1 Introduction

1.1 Problem Statement

Over the last decade with the increased activity in deep water, highly deviated wells, horizontal drilling, multilateral wells and high-end costly completions, the need to improve upon wellbore cleaning has became more of concern for operators around the would. A clean wellbore is not only a prerequisite for trouble a free well testing and completion. It also helps ensure optimum production for the life of the well.

The importance of wellbore cleanup is often overlooked, and its impact on the entire operation goes unrecognized. Yet gunk, junk and solids are a real threat to future production. In fact, the most frequent and expensive cause of NPT is debris left in the wellhead area: Debris often falls down into the well resulting in problems in installing the completion and poor cleaning can often result in the upper completion having to be pulled.

Debris left in the wellbore after drilling, milling, and scraping a well can ruin a complex, multi-million dollar well completion. It can prevent a completion from reaching total depth, and it is highly probable that the well will fail to reach optimum production levels without a clean wellbore.

All this cleanout problems actually requires relatively little effort and equipment to solve, greatly reducing occurrences and the cost of NPT during the completion phase.

A clean wellbore is one of the most critical aspects of a productive, trouble free completion. A clean production cased wellbore increases the ability to set and retrieve downhole completion tools. More importantly, a clean wellbore ultimately leads to enhanced production through reducing or eliminating fine solids that are potentially damaging to the formation.

A successful wellbore cleanup requires the right combination of:

• The optimum cleaning/displacement chemicals. • The correct mechanical downhole cleaning tools.• The proper pre-job planning, design and onsite implementation.

Thorough displacement of drilling fluids from casing and other production tubing, as well as surface equipment, has dramatic effects on well productivity and economy. For a successful completion to occur, the drilling mud and associated contaminants such as scale, rust, bacteria, pipe dope and other solid material must be displaced and the tubulars thoroughly and efficiently cleaned. Failure to perform an effective cleanup can lead to problems in the form of increased rig time, higher cost, lower mud recovery, reduced productivity, mechanical failure, pitted tubulars and costly workovers.

The big issues are to Reduce rig rate time and do the wellbore clean-up cost effective.

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1.2 Objectives

Determine the most economic Well Clean-up Procedure(s) for SASBU’s operations. Develop guidelines to ensure that all rigs are performing clean-ups optimally.

We can achieve these objectives by getting a thorough knowledge about the problems that we face if we don’t clean the wellbore, and analyzing the main points regarding to this problem to provide the best procedures for wellbore clean-up.

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Chapter 2 General Considerations

2.1 What is wellbore clean-up?

Is a cleaning operation done after the well is drilled to TD; this is before completion in order to avoid downhole completion tools failure and formation damage.

2.2 Why do we clean-up the wellbore? Today ours goal is to complete the well on time. Producing or injecting longer, and at low cost; so we do wellbore clean-up because we want to achieve the following benefits:

• Increased productivity and mud recovery• Reduce Rig time• Reduced filtration time and expense• Maintain the integrity of the completion fluid• Fewer mechanical failures of downhole equipment• Reduce corrosion pitting

The critical bridge between drilling and completion required to optimize the wellbore production; delivering significant saving and improved return. We call this entire path as a wellbore assurance. The aim of wellbore assurance is simple to safeguard your success.

Optimizing the condition of both the wellbore and the fluid system before completion is proven to extend the productive life of every well, and reduce the incidence of unplanned workovers. A highly effective wellbore clean-up solution is proven to pay for itself many times over. It has been widely recognized that performing a properly planned wellbore clean up as part of the pre-completion operation significantly reduces the incidence of problems with the completion installation, to achieve the following goals:

• Reduce operating cost • Eliminate non-productive time • Protect the formation • Guarantee on time production• Prolong completion life• Improve safely• Prevent environment impact

2.3 How and where do we do clean-up?

We do wellbore clean-up by chemical and mechanical means. These operations are focused on wellhead, downhole, fluids, environment, formation and completion.

1. Wellhead

As the surface termination of the wellbore the wellhead is the gateway to the well. Operations such as casing and production hanger installation demand high degree of cleanliness and

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Wellbore Clean-up

preparation. So we need a solution to assure a clean surface and sub-sea wellhead, as well as a clean marine riser.

2. Downhole

Wellbore debris is known to contribute to over 30% of NPT during the completion phase. A structured and carefully-engineered wellbore clean-up strategy is proven to reduce this.

3. Fluids

During drilling and completion phases, the removal of solids particulate from mud and brines eliminates the threat of impaired production. Additionally it assures the performance of downhole equipment and technology.

4. Environment

Whether on land or offshore, oil-base mud and other hazardous are an environment problem if incorrectly managed, an effort is needed to be done in order to minimize and mitigate these risks, by conforming to regional legislative requirement.

5. Formation

Production rates can be substantially reduced if the formation is impaired in its ability to flow, due to plugging of the reservoir throats. Clean-up solutions apply to both drilling mud and completion fluids, enabling the removal of solids while managing ECD in the drilling phase. The quality of the completion fluid after mud displacement is also assured.

6. Completion

Any failure during the installation process concerning the completion has the potential for significant impact on the performance of the well. Failures of this type consistently cause substantial NPT and ultimately result in the need for unplanned workover of the well and loss of production. 2.4 Completion Type and Wellbore Clean-up The completion type has a great influence on the way as the wellbore clean-up should be done, because we need to identify the types of damage associated with each type of completion.

Basically during drilling and completion operations we are faced with two damage mechanisms. The first category is termed formation damage and second one is considered completion damage. Each damage type is located in distinctly different areas of the producing system. Their potential to impact production can also differ greatly. Formation damage is defined as permeability impairment induced to reservoir rock itself. Completion damage, on the other hand, refers to materials, residue or contaminants contained within the confines of the borehole that can hinder productivity or reliability.

2.4.1 Formation damage

A formation damage mechanism can be defined as any mechanism or process that results in a reduction in permeability of a producing zone.

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The problem of assessing fluid compatibility with hydrocarbon reservoirs is ongoing and usually unique to each reservoir. This problem becomes most visible after resources have been expended to drill, with unsatisfactory results in productivity.

We want to minimize formation damage to increase productivity index and reduce unnecessary costs through optimal use of drill-in and completion fluids, tools and well-cleaning techniques. Therefore, it is necessary to plan procedures and implement practices to reduce formation damage and maximize productivity at the earliest possible stage. Proper selection of the completion fluid is an integral part of this process.

Completion fluid can be defined as any fluid pumped downhole to conduct operations after the initial drilling of a well. Clear, solids-free brine completion fluids serve to control downhole formation pressures while reducing the risk of permanent formation damage resulting from solid invasion or some incompatibility between the completion fluid and in situ matrix.

The clear brines used for completion and workover are pure solutions of dissolved salt in water and must be stable at surface and downhole conditions. Packer fluids are those that fill the annular volume above a production packer. The term reservoir drill-in fluid refers to a drilling fluid designed specifically for the productive interval. Drill–in fluids are designed to minimize damage to interval, typically by eliminating insoluble solids such as barite, minimizing the total content and formulating such that a thin, resilient, removable, non-damaging filter cake is placed in wellbore walls.

2.4.1.1 Types of Formation Damage from Fluids used in Completion

Formation damage, either chemical or physical, reduces the productivity of a well. The basic causes of formation damage are:

• Hydration of formation clays• Wettability changes• Pressure differential• Water blocking• Emulsion blocking• Paraffinic or asphaltic plugging• Formation of precipitates• Migration/dispersion of formation clays

One or more of these causes may exist simultaneously in a well. Selecting a properly designed, compatible fluid is a means of mitigating these effects.

2.4.1. Sensitivity Studies

To evaluate reservoir potential, sensitivity studies should be undertaken when possible. In order of preference, pressure cores, conventional cores, sidewall cores, or cuttings should be used to perform the evaluation and sensitivity studies. Tests to be performed should include:

1. Formation Description

• Pore throat lining and bridging material (XRD, SEM/EDX)• Thin section - petrographic microscope analysis

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• Reservoir fluid analysis• Porosity and permeability• Pore throat size and distribution

• Vugularity

2. Formation Integrity Tests

• Return permeability• Rock/fluid and fluid/fluid interactions• Acid solubility• Matrix strength

3. Formation Pressure

Determining formation pressure is crucial to fluid selection economics, minimizing formation damage, and maintaining operational safety. Formation damage is greatly reduced by operating under-balanced using a non-damaging, solids-free fluid, but the risks are high. Not only must experienced and trained crews be employed, but also specialized equipment is needed. While it is desirable to maintain 100-200 psi over formation pressure, this is often difficult to achieve. Pressure sensing devices, such as the Hewlett Packard quartz pressure sensor, or a manometer survey tool (Bourdon Tube gauge), are useful for determining formation pressure. However, actual well conditions may dictate adjustments to these determinations in order to maintain well control during operations.

4. Formation Clay Swelling

The chemical composition of a fluid, formation water, type of clay in the formation, and/or secondary clay deposits lining a pore throat must be carefully considered when selecting a fluid. Rock-fluid and fluid/fluid interactions can result in formation damage such as swelling of the clays, migration of fines, and the formation of precipitates.

5. Oil Wetting of Reservoir Rock

Most reservoirs are water-wet or preferentially coated with a film of water. Consequently, if oil wetting additives are used in a fluid that comes into contact with the formation, oil movement across the grains becomes severely restricted. This will cause the formation to produce water more readily and may result in the formation of an emulsion block and/or water block.

6. Mixing Facilities

Rig site mixing is generally poor for fluids that require shear; however, the problem can be resolved through the use of portable high-shear mixers. If large volumes of fluids are to be mixed, then pre- mixing at a mixing facility should be considered. Safety considerations are another factor that limit the mixing of fluids at the rig site. Generally, fluids are pre-mixed at a mixing facility, then delivered and maintained at the rig site.

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7. Corrosion

Some fluids produce high corrosion rates and require pH adjustments and/or the addition of corrosion inhibitors. Consideration must be given to the use of corrosion inhibitors for economics as well as fluid compatibility.

8. Economics

Proper fluid selection should always consider economics. Remediation, treating or stimulation operations due to an improperly selected fluid can be costly. Contaminants such as cement, salt water, acids or surfactants, along with bacterial growth and safety are important factors to be considered in selecting an economical workover/completion fluid.

Generally, reservoir drill-in fluids should be designed and selected based on fairly comprehensive set of criteria. Depending on the application, the selection may include:

• Density and the ability to adjust as needed• Thermal limits• Shale control• Rheology (hole cleaning and ECD)• Environmental Compliance• Crystallization behavior of base fluid• Formation compatibility (including fluid-fluid interaction)• Contamination tolerance• Ability to execute the completion as designed• Fluid displacement method• Wellbore cleanup and efficiency

Among the typical operations in which clear brines are applied are well kills, fishing, perforating, washing, drilling and gravel packing and as packer fluids. In order to perform the desired function, completion fluids must control formation pressure, circulate and transport solids, protect the production zone, be stable under surface and downhole conditions, be safely handled, be environmentally friendlily or used with control exposure, and be cost effective.

2.4.2 Completion damage

A completion damage mechanism can be defined as Hindrance of well productivity by deposition and flow modification at and around wellbore.

This type of damage as we said before refers to materials, residue or contaminant contained within the confines of the wellbore that can hinder well productivity or reliability, we want to focus specially on debris which can cause serious problems during completion tools installation, wellbore debris is known to contribute to over 30% of NPT during the completion phase.

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2.4.2.1 Debris Categorization

DescriptionDebris can generally be described under three categories:Solids generated during the well construction process as typified by:• Barite due to mud settlement• Cuttings (cement and formation) due to poor hole cleaning• Swarf from milling operations• Mill scale rust and other solids from poorly prepared tubulars

Gunk from the fluid used in the well construction process, such as:• Pipe dope• Viscous muds (milling fluids and synthetic muds at low temperature)• Gelled oil based mud after mixing with water

Junk introduced to the well e.g.:• Seals/elastomeric materials from BOP and seal stacks• Cement plugs and float equipment after drill out• Perforation debris• Bandit materials accidentally introduced e.g.:- Wood from pallets/dropped objects (tools / clamps)- Hoses

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Chapter 3 Wellbore Displacement

Once a well is drilled to TD, completion operations commence. The first step in the completion process is typically a displacement of the drilling mud to clear brine. This process is necessary to maintain the functionality of downhole tools and the integrity of the productive interval. During this phase, however, the formation is the most vulnerable to potential damage from completion fluids. This is because the completion fluid can easily be contaminated by components of the drilling mud if the initial displacement of drilling mud is not effective. Once contaminated, the completion fluid is no longer a non-damaging fluid and may not contribute to a high-efficiency completion. In addition, an inefficient displacement design consumes expensive rig time by prolonging the fluid circulation time in order to achieve an acceptable level of fluid cleanliness for formation damage control.

Traditionally, the wellbore cleanout process has not received significant attention because of a lack of understanding about the impact of formation damage by particle plugging on well productivity. Furthermore, the complex nature of fluid transport mechanics and the lack of laboratory testing and correct methodology for evaluating the displacement-chemical performance may contribute to the inefficiency wellbore cleanout practices.

When displacing fluid in a wellbore over from one type to another, the most important factor is to create a sharp interface between the two fluids to minimize contamination and waste. Steps must be taken to minimize channeling and ensure as complete a removal of the fluid being displaced as possible. Spacers can be formulated to provide separation of the fluids whether the displacement is mud to mud, brine to mud, or mud to brine.

The universal goal for a displacement program is to effectively remove all drilling mud residues from the wellbore. Although operators and service companies share this common goal, there are many different approaches that can be implemented to accomplish the task. The number of different displacement techniques and varied approaches to wellbore cleanup often lead to confusion about which procedure is best suited for a particular situation.

3.1 Displacement Objectives

The basic displacement objective is the same regardless of the completion type or procedure. A successful displacement should accomplish the following:

• Remove mud and unwanted debris from the open hole, casing and riser (if applicable)• Maintain the integrity of the mud and completion fluid interface• Minimize rig time• Minimize brine filtration and expense• Minimize waste and disposal costs• Accomplish these tasks with lowest risk to personnel and the environment • Minimize the overall cost for the operator• Maximize well productivity

Proper execution of a given displacement procedure will minimize the need for stimulation and promote the ultimate deliverability of a clean, undamaged and productive wellbore.

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3.2 Displacement Design Considerations

3.2.1 Pre-Job Planning

To design a displacement procedure that will meet the objectives of the completion requires the input of the following basic data:

• Type of completion• Type of drilling mud and completion fluid• Casing and work string design• Measured depth and true vertical depth• Mud-line temperature• Bottom hole temperature and pressure• Rig-site facilities and logistics to transfer and remove mud from well location• Pump outputs• Water availability• Environmental concerns

The necessity and importance of pre-job planning can not be over-emphasized because poor planning or design based on incomplete information may result in poor displacement.

A careful evaluation of pressure differentials, frictional pressure losses and pump rates, based on the density and viscosity of drilling and completion fluids, spacer design (composition, density, viscosity and volume), wellbore configuration is required for an effective displacement design.

For deep water completions, the mud line temperature may necessitate the selection of a completion fluid with a lower crystallization temperature than that might otherwise be required, especially if the BOP is planned to be tested with a completion fluid. The selection of completion fluid influences the displacement design. Large diameter risers require the availability of very large volumes of fluid for achieving a successful cleanup. The cool temperatures and high pressures in deep water increase the possibility of the formation of gas hydrate. This possibility exists if gas migrates during displacement, especially if a liner top fails during displacement.

The pit space is critical in the displacement design. Sufficient pit space is required to complete the displacement without pump stoppage. Limited pit volumes may influence the pump rate and the ability to mix pills and spacers on the rig. If the pills and spacers are mixed at the plant and transported to the rig, a manifold system may be required for a smooth transition from one pill or spacer to another.

Often, changing the workstring design enhances the displacement efficiency. Increasing the size of workstring reduces friction pressure and annular volume, thus providing the opportunity to pump the chemical spacers in turbulent flow regime.

3.2.2 Pumping Direction

Displacement is designated according to the direction in which they (Displacement fluids) are pumped and the fluid which follows the chemical spacers into the hole.

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In the forward technique, displacing fluids are pumped down the workstring and up the casing annulus and the pressure is applied to the workstring. Forward circulation allows rotation and reciprocation of the workstring when the blow-out preventer and pipe rams remain open. Pipe movement is important in a deviated wellbore. Forward circulation allows higher pump rates and less frictional pressure losses over the course of displacement. It also allows greater control over differential pressure across sensitive areas such as liner tops and squeezed perforations. This can be achieved with backpressure. However, the rotation and reciprocation of the workstring is less likely if the wellbore requires back pressure on the annulus. A significant advantage in forward pump direction is that the pump pressure is contained in the workstring rather than transmitted to the annulus.

In the reverse technique, displacing fluids are pumped down the casing annulus and up the workstring and pump pressure is applied to the annulus. Reverse circulation minimizes the interface contamination between high-density mud and lower density spacers or completion fluid. It also aids in removing debris from the well by working with gravity to push debris to the bottom of the hole. The debris at the bottom of the well can then be more easily circulated back up the workstring using the higher velocities that occur in the tubing vs the casing due to the normally smaller cross sectional area of the tubing string. Reverse circulation is often utilized as a first stage in an indirect displacement in which the mud is reversed-out of the hole with water and then the annulus and workstring clean-up is pumped in forward direction.

Pumping in the reverse direction often produces less hydrostatic differential pressures because the lower density spacers generate less linear coverage in the annulus than in the workstring. This scenario can be advantageous when pump output is rather limited. The drawback of the reverse circulation is that the pipe movement is limited because the reverse circulation is carried out with the annular pressure control equipment closed.

The benefits of reverse circulation are that the elevated flow velocity up the workstring enhances debris removal, and the lower workstring volume, as compared to the annular volume, allows “bottoms-up time” to be much shorter, which in turn allows for closer monitoring of the bottom hole condition. However, there is another disadvantage to the reverse circulating technique. The drawback is that the friction pressure from pumping through the entire length of the workstring at a high rate is imposed at the bottom of the wellbore, rather than at the surface.

Figures 3.1a and 3.1b show the difference in pump pressure requirement and pressure applied to the formation for a forward and reverse circulating technique in a typical casing and workstring at 7 bbl/min.

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Comparison of Pump Pressure Required forForward / Reverse Circulation

Figure3.1a In a typical casing and workstring, displacement at 7 bbl/min requires a different pressure profile depending on whether forward or reverse circulation is used.

Friction Pressure and Annular Velocityvs Pumping Rate

Figure 3.1b this chart illustrates the significantly higher pressures that can be applied to the formation due to pumping in reverse as compared to pumping in the forward direction. Example: The 300 ft/min velocity required to clean the open hole at a rate of 7 bpm will result inapproximately 900 psi more pressure applied to the formation when pumping in reverse vs. the forward direction. In some cases this could result in formation breakdown and high fluid losses.

3.3 Displacement Types Displacements are classified as direct, indirect, balanced or staged. They can be pumped in either forward or reverse pumping direction. In forward displacement, the fluid is pumped down the workstring and returns are taken up the annulus. Conversely in reverse displacement, the fluid is pumped down the annulus and returns are taken up the workstring. Each type has its advantages and disadvantages.

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3.3.1 Direct Displacement A direct displacement is one in which the chemicals spacers are directly followed by the completion fluid (Figure 2).

A. Water

base- mud B.

Oil/Synthetic-based mudFigure 3.2 Schematic of direct displacement. Note that chemical spacers are directly followed by the completion fluid.

Since these spacers are the only intermediaries between the drilling mud and the completion brine, they must be designed to perform all of the separation and cleaning functions. A direct displacement is desirable when: (1) discharge of the mud or returns is restricted due to environmental concerns, (2) and inexpensive water supply is unavailable, (3) a balanced displacement or back pressure is required, and (4) well control issues such as suspect liner tops and open or squeezed perforations are of concern. The direct displacement is typically pumped in the forward circulating direction.

This method is often favored because the rig time (cost) is reduced. Improved procedures have advanced significantly, reducing the number of spacers required to clean the open hole and casing effectively.

3.3.2 Indirect Displacement

Indirect displacements refer to the circulation of the entire wellbore with available water prior to introduction of the completion fluid (Figure 3.3). This technique is typically used when there is an inexpensive supply of water and the environmental impact of discharge is acceptable and when the pressure differential caused by the difference in density between the water and drilling fluid can be tolerated. One advantage over the direct method is that the completion fluid is not introduced into the wellbore until the tubulars are relatively clean.

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Figure 3.3 Schematic showing indirect displacement of water-based mud.

For example, if oil-based drilling mud is used to drill down to the production zone where a liner is set, one may wish to displace and clean the pipe with seawater before displacing to water based drill-in fluid. The seawater would be preceded by a series of spacers and solvents to clean and water-wet the casing. With this method, a thorough cleansing can occur with minimal product usage due to the circulation of inexpensive water. Later, the displacement to the clean, drill-in fluid will occur without contamination. For indirect displacements where a liner is set, a good cement bond log is necessary because high differential pressures on the casing could cause a collapse or breakdown of cement.

Indirect displacements may also be recommended for the production casing. In this instance, the drill-in fluid would be displaced to drill-water before finally being displaced to clear brine. Caution must also be exercised in this displacement because a possible reduction in hydrostatic pressure across the production interval could lead to a casing collapse. Improved cleaning techniques (specialized spacers) and increased daily rig costs have reduced the use of indirect displacements.

The following scenarios are instances where an indirect displacement may have the best application:

• Riser Displacement: Displacing and cleaning the riser in a deepwater application before displacing mud from the deeper intervals can be a prudent exercise. Due to its large capacity and the need for large spacers, large volumes of seawater and nominal volumes of specialized chemical spacers will clean mud from a riser. In this example, the blind rams would be closed to prevent communication with the fluids below the riser. Waiting to clean the riser with the spacers from the smaller diameter sections can be less effective unless special procedures and chemicals are used.

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• Oil or Synthetic-Based Muds (OBM/SBM) to Water-Based Mud (WBM) in Casing: When displacing OBM/SBM in a drilling liner to WBM, oil and oily cuttings can contaminate the drill-in fluid. The use of large volumes of flush water with a solvent spacer can ensure that most oily contaminants are removed and the casing is sufficiently water-wet before introducing WBM. Daily rig costs could prohibit this practice.

3.3.3 Staged Displacement A staged displacement refers to working down the wellbore with the workstring while displacing mud with water or completion fluid, i.e., staging in. For example, a 10,000 foot well may be displaced in two stages in which the top 5,000 feet is displaced and then the bottom 5000 feet displaced. This procedure is used when the differential pressures are so great that possible damage to the casing or excessive pump pressure make a more typical displacement risky or logistically unrealistic. Interface volumes between the stages are large and extensive contamination of both the mud and the completion fluid usually occurs.

3.4 Operational Considerations

3.4.1 Surface Pits and Clean-up Equipment

Clean working practices and good housekeeping cannot be over-stressed when displacing to a completion fluid. Specific cleaning procedure will depend on mud type:

3.4.1.1 Invert Emulsion Systems (O/SBM)

(a) Pump surface volume of mud into containers suitable for transfer the final destination. Remove any solids built up in pits, corners and discharge areas by mechanical means. A vacuum system will greatly enhance the solids cleanup of the surface equipment. Also, with a high temperature /high-pressure washer, external areas can be cleaned thoroughly.

(b) Mix 1-2 drums of a surfactant blend into 100-150 bbls of water and flush all hoses, lines and pumps thoroughly, taking returns back to the same pit. Pump this chemical at the maximum safe rate.

(c) Using the same fluid as in Step (b) above and with the pipe rams closed, pump through all choke/kill lines, manifold and rig floor standpipe equipment to thoroughly remove all OBM or SBM residue. Pump at the maximum safe rate. Dispose of as per operator procedures.

3.4.1.2 Water-based Systems

(a) Pump surface volume of mud into containers suitable for transfer to final destination. Remove any solids built up in pits, corners and discharge areas by mechanical means. A vacuum system will greatly enhance the solids cleanup of the surface equipment. Also, with a high temperature/high pressure washer, external areas can be cleaned thoroughly.

(b) Mix 1-55 gal drum of an alcohol/surfactant blend per 50 bbls of water and flush all hoses, lines and pumps thoroughly, taking returns back to the same pit. Pump this at the maximum safe rate.

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(c) Using the same fluid as in Step (b) above and with the pipe rams closed, pump through all choke/kill lines, manifold and rig floor standpipe equipment to thoroughly remove all OBM or SBM residue. Pump at the maximum safe rate. Dispose of as per operator procedures.

3.4.2 Condition of the Mud

The rheological properties of drilling mud are designed to drill the well. The ability to suspend solids in a static mode is crucial to its success in that application. The same rheological profile used for drilling is not ideal for the transition from drilling mud to clear brine. If the mud has remained in the wellbore in a static mode for any significant period of time, its viscosity and gel strength will be significantly higher than when the mud was being circulated during the drilling phase. These conditions are exacerbated as the density of the mud and temperature and angle of the wellbore increase.

The opportunity for success during displacement is greatly enhanced by circulating and conditioning the mud through chemical and mechanical means. In fact, fluidizing the mud is considered the most important step in the displacement process. Proper foresight and planning are necessary to identify the opportunity to adjust the viscosity of the mud at some point prior to pumping the displacement. Key parameters to consider include mud rheology, i.e., plastic viscosity (PV) and yield point (YP) and gel strength, pipe movement, pipe centralization and mechanical aids such as brushes and scrapers.

The mud properties should be reduced to minimum levels for high pump rates and solids transport. A guideline is provided in Table 1 below:

Table 1 – Conditioning the mudProperty Straight or Moderately

DeviatedDeviated more than 60°

PV 15 or lees Greater than 15YP Less than 10 Around 25Gels 10s/10m Similar and less than 5 Similar and less than 10

Fluidizing the mud is enhanced by circulating well-conditioned mud at the highest flow rate possible and with as much mechanical aid as possible. A bit and scraper run, pipe rotation and reciprocation are important mechanical means used to aid in removing pockets of gelled mud and mud cake while circulating the mud at the highest possible rates.

3.4.3 Pump Rate

Pump rate determines the flow regime of the mud, spacers and completion fluid. It is generally accepted practice to design a displacement to achieve turbulent flow for any chemical “wash” spacer. A turbulent flow pattern for surfactants and solvents ensures a uniform flow profile, reduces interface fingering and ensures good contact of the chemical cleaner with the surface of the mud cake under eccentric pipe. Displacement efficiency is greatly improved when all non-viscous spacers, or pills, are pumped in turbulent flow. However, when turbulent flow can not be achieved due to pump or wellbore restrictions, efficiencies are highest when the wash pills are pumped at the highest rate possible.

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3.4.4 Hydraulic and Pump Pressures

Pressures determine which direction the displacement is pumped, i.e., forward or reverse. Hydrostatic and frictional pressure losses are calculated for both pumping directions and the method that best meets the design considerations is selected. Pressures determine the required pump horsepower to obtain the flow rate that will put the chemical cleaner spacers in turbulent flow when in the widest annulus. If the pressures are excessive or the pump output is less than required for turbulent flow, spacer volumes and chemical concentration of the “wash” pills are increased to extend contact time and add chemical energy to the system.

3.4.5 Mechanical Assistance

Standard casing scrapers and casing brushes (Figure 4) can be beneficial for many displacements. These devices will help remove any solids that may adhere to the casing walls so the displacement fluid can move them out of the hole. A short trip with these tools in the hole will also enhance the solids removal. Scrapers and brushes are placed near the bit, close to the liner tops, and midway to the surface. Jet subs and other pressure washing tools can also be beneficial. As with pipe movement, mechanical aids change the flow path of the fluids and provide access to low side mud cake. They also induce turbulence as the fluid travels around and through these devices.

Figure 3.4 Scraper-brush combination tools.

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3.4.6 Spacers

Industry wide, the spacer (or pill) system design is one of the more disparate components in displacement technology. Every displacement pumped includes a spacer ‘system’ of some kind and the functions and objectives of the spacer system as a whole are the same in all cases. However, preferences differ from one operator to another and from one service company to another. Weightedspacers, viscous pills, base fluids, surfactant type and concentration, solvents, spacer sequence, contact time, volume and effective flow regime are among the many questions that must be addressed by the completion engineer.

Most completion fluids are not compatible with drilling mud. As the density of the mud and completion fluid increase, compatibility is increasingly difficult to achieve. High-density brine completion fluids will dehydrate water based mud (WBM) and gel with oil and synthetic based mud (O/SBM). Therefore, the first function of the best spacer system is to separate the two incompatible fluid system and prevent interaction between the completion fluid and the mud whether at the whole mud interface or with residual mud left behind in pockets.

Compatible Spacer Prevents the “Viscosity Hump”

Figure 3. 5 Compatible spacer prevents the formation of “viscosity hump".

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Figure 3.6 An example of various spacers utilized in the displacement of water-based mud.

The spacer system starts with “compatible” spacer (Figure 3.5), designed to provide a smooth transition in density and “chemistry” from the whole mud to the next spacer – typically the “wash chemical”. In the case of water based mud (WBM), this relatively simple task (Figure 3.6).

A viscous water spacer, which may or may not be weighted, is typical. The high viscosity helps maintain the integrity of the spacer by enabling it to stay in “plug” or laminar flow at high pump rates (Figure3.7).

The spacer must be large enough to allow for 5 to 10 minutes contact time based on the pump rate. Pipe rotation helps break up the gelled pockets of mud that may accumulate in some sections of the annulus, especially in highly deviated wellbore. The density of the lead spacer should be adjusted for well control reasons and should be at least or slightly more dense than the fluid being displaced. Oil and synthetic based muds require a more sophisticated formulation (Figure 8), usually accomplished with water as the base for a viscous fluid and a surfactant that emulsifies the oil mud into the water phase.

The next spacer is the cleaning spacer. This is the spacer that should be in turbulent flow (in the widest annulus). In some cases, this cleaning spacer is water that contains a specially formulated surfactant. Some companies run their surfactant or solvent neat (100%). If a solvent is run, a water/surfactant spacer to water-wet the pipe follows it. Finally, another viscous pill is run to separate the completion fluid from the cleaning spacers. The volume for each of these spacers is a function of the wellbore parameters and surface equipment. As a general rule, the volumes of most of the spacers are designed to cover 500 – 1500 linear feet in the largest annulus.

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Water Based MudSpacer

WBM

Viscosified / weightedSpacer (+/- 500’ Annulus)

Water Spacer withCaustic (+/- 750’ Annulus) and/or

Chemical Wash Spacer (1000-1500’)

Viscosified BrineSpacer (500’)

Completion fluid

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Figure3. 7 Flow regime during displacement.

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Completion fluid

Viscous Spacer (HEC) (500’

Concentrated SurfactantsSAFE-SURF O (1500’)

HydrocarbonSolvent or base oil

(+/-500’)

(Forward Circulation)

3 - 7

Oil Mud

Direct Displacement – O/SBM

Direct Displacement – O/SBM

Brine Viscous Spacer

(HEC) (250-500’)Concentrated SurfactantsSAFE-SURF O (1000 -1500’)

Weighted or Viscous SpacerPlus SAFE-SURF O (+500’) Oil Mud

Based Oil Solvent(+/-500’)

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Figure 3.8 Examples of various spacers utilized for the displacement of oil / synthetic-based mud.

The spacer design is a function of the type of mud in the hole and the completion fluid to follow. Water based mud (WBM) displacements are considered by some to be the easiest systems to design because water is an excellent thinner and dispersant for these muds (Figure 6). The more water pumped between the completion fluid and the mud, the better the chance for a clean wellbore. Depending on the type of WBM, caustic, surfactants and/or flocculants are added to the water to aid in dispersing the mud solids into the water. Pressure differential limitations, particularly when a direct displacement is called for, may prevent large water spacers. In such cases, surfactants and other cleaning aids are important to effect the cleaning in a short period of time. Table 2 depicts a typical spacer sequence for WBM and O/SBM.

Table 2 Spacer DesignTypical Spacer System

WBM O/SBM FunctionWater Base oil Thin/condition mudViscous pill1 Viscous pill1 + OBM

surfactantSeparate/transition

Water + WBM surfactant Water + OBM surfactant cleanViscous pill2 Viscous pill2 Separate/transitionCompletion fluid Completion fluid Complete well1 Weighted close to density of mud. Viscosity greater than mud2 Prepared in completion fluid

Spacer contact time in the wellbore is determined by the volume and type of spacer, the annular flow rate, the fluid and density being displaced and the wellbore configuration. Contact time is critical in the clean up process because removal of debris occurs gradually as a spacer flushes past the wellbore surface. In most applications, the contact time may vary somewhere between 2.5 to 10 minutes. The concentration of the solvent in the spacer also plays a significant role in clean up, especially in the removal of oil-base and synthetic-base residue. In these and other applications, the volume of the spacer and the displacement rate determine the contact time. Usually the displacement rate is based on the annular flow rate needed to achieve turbulent flow however, hole or rig conditions may limit the pump output. Once the volume is calculated for optimum contact time at the agreed upon displacement rate, the appropriate solvent concentrations can be optimized. For the removal of oil/synthetic debris, concentration requirements are calculated based on the

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Wellbore Clean-up

surface area of the wellbore (casing or open hole). Programs are available to calculate precise contact time requirement for specific applications.

When a displacement can not tolerate a low-density spacer because of the ensuing pressure differentials and back-pressure can not be maintained, a completely balanced spacer system is necessary. In these circumstances the spacers are formulated to provide separation, density transition and the cleaning process. The first viscous spacer is weighted to match the density of the drilling mud and will generally have a higher viscosity than the mud. In some cases, this is either followed by completion fluid containing surfactant or with another viscous pill, depending on the nature of the mud. OBM displacements (Figure 3.8) include surfactants in the viscous pill to make the transition from oil –to- water external emulsions and to water-wet the pipe. When the pills are pumped without a non-viscous solvent or water/surfactant spacer, turbulence is generally not possible and one must count on the chemicals and whatever mechanical aid is available to provide the wellbore cleaning. Although this type of procedure is performed many times in the field, a careful examination of the compatibility of the spacers with the drilling mud and completion fluid should be performed in the laboratory. Field experience has shown that displacing a wellbore without the ability to clean the pipe with a non-viscous, low-density, water based surfactant spacer has the potential to cause operational problems when a sand control completion follows.

3.4.6.1 Laboratory Spacer Formulations and Compatibility

Most completion fluids are not compatible with drilling mud, especially as the density of each fluid increases. High-density brine completion fluids will flocculate and dehydrate most conventional WB mud and gel with OB mud. Therefore, the first function of the spacer system is to separate the two incompatible fluids and prevent an unfavorable interaction between completion fluid and the mud – whether at the whole-mud-interface or with residual mud left behind in pockets. The spacer system should accomplish this separation without inducing large interface volumes between the mud-spacers-completion fluids. Furthermore, the transition from mud-to-completion brine should be smooth in terms of density and "chemistry" (Figure 3.9).

3.4.6.2 Base Fluid Spacer

If the drilling mud has not been properly conditioned or has not been circulated, the mud- gel may not be broken before displacement begins. In such cases, movement of mud in the narrow side of the annulus can be significantly slower than on the high side. To effect movement, the spacer system may start with a small volume of base fluid to thin the mud and reduce the energy required to break the gel. This base fluid is simply water for WBM and oil for O/SBM. However, caution must be exercised because too much base-fluid will thin the mud to the point that it will loose its ability to suspend and carry barite and drill solids. In such cases, the remaining spacers and completion fluid may be highly contaminated with these solids.

3.4.6.3 Transition Spacer

The transition spacer is a viscous pill designed to provide a chemical transition from whole mud to WB spacer – typically the “wash chemical”. In the case of WBM, this is a relatively simple task as long as the transition spacer is formulated in fresh water. A barite-weighted, viscous water spacer is often used to ensure chemical compatibility with WBM. However, the use of barite as a weighting agent must be carefully considered because a poorly designed weighted spacer can cause more problems with barite removal than is solved with its better density profile.

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Wellbore Clean-up

High viscosity helps maintain the integrity of the mud by displacing in a “piston-like” manner at high pump rates. The volume must be enough to ensure the interface at the front and back of the spacer do not intermingle. Depending on the pump direction, the density of the lead spacer should be adjusted according to the density of the mud being displaced. For example, when pumping in the forward direction (i.e., down the workstring and up the annulus), the density of this spacer should be equal to or slightly greater than the density of the mud. Oil and synthetic based mud require a sophisticated formulation, usually accomplished with water as the base for a viscous fluid and surfactants/solvents that demulsify the oil-mud into the water phase.

The chemical formulation and design of the transition spacer is crucial to the efficiency of the wash spacer that follows it. This phase transition is one of the most critical factors for well productivity in wells that are drilled with OBM and gravel packed with water-based fluids. OBM are water-in-oil emulsions, containing emulsifiers and organophilic clays to stabilize the emulsion. As such, OBM are inherently incompatible with WB fluids, particularly with high density completion brine, and will develop a thick sludge-like emulsion at the interface between the completion fluid and the OBM. This sludge-like consistency is a result of incorporation of water droplets into the OB-WB interface (emulsion).

Interface instabilities are inherent to cases where the displacing fluid has lower viscosity than the displaced fluid, regardless of the flow regime. Increased internal aqueous phase volume fraction in such emulsions increases the viscosity of the emulsion drastically when the internal phase fractions exceed ~50-75%. Such emulsions are highly shear-sensitive and can thicken to mayonnaise-like consistency if sufficient emulsifier exists in the OBM that is being displaced. When thick emulsions develop, the low-viscosity water-based spacers and displacing brine bypasses the thick emulsion, leaving pockets of mud and emulsion in the wellbore. These undisplaced pockets of thick emulsions can be trapped in the gravel pack during gravel packing and result in extremely low productivities. It is therefore extremely important to use proper spacer fluids between the OBM and completion brine.The volume and the chemistry of the spacers must be carefully selected through laboratory experiments and numerical simulations (Figure 3.9).

Figure 3.9 A properly formulated OBM "Transition Spacer” prevents gelling at interface. Spacer A is formulated to prevent a thick emulsion from forming at the OB-WB interface. Spacer B is representative of a ‘typical’, viscous spacer – without appropriate additives.

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Wellbore Clean-up

Transition spacer compatibility can be determined through simple laboratory experiments. Figure 3.9 shows the results of the compatibility tests between the OBM and two viscous spacers A and B, where spacer A is an optimized formulation while B is not. Both spacers A and B were formulated in the completion brine to maintain the same density between the OBM and spacer. In these tests, OBM and spacer are mixed at various volumetric ratios simulating the mixing zone between the two fluids and the rheology of the mixtures measured. A gradually increasing viscosity from that of the OBM to that of the spacer is noted for spacer A, while spacer B yields a mixture of much higher viscosity than either the spacer or mud when the volumetric ratio of OBM to spacer is 50/50. Spacer A was made compatible by incorporating a combination of an oxygenated organic solvent with nonionic and anionic surfactants into the HEC-viscosified brine pill. In this case, the solvent and surfactants were added at 5-vol% and 3-vol%, respectively.

3.4.6.4 Wash Spacer

The wash spacer is the only spacer designed to clean the pipe surface of mud and leave the surface water-wet. The most effective cleaning is accomplished when only a thin film of mud left behind after the transition spacer and the wash spacer is pumped in turbulence. In most cases, this cleaning spacer is water that contains a specially formulated surfactant. Some companies run their surfactant or solvent neat (100%). If pure solvent is pumped, a water-wetting surfactant spacer follows it and both spacers are considered the wash spacer. The volume required for the wash spacer depends on wellbore and surface equipment factors, however, as a general rule, this spacer is designed to cover 500 – 1500 linear feet in the largest annulus.

The size of the cleaning spacer is dependent on the pump rate to a much greater extent than are the viscous pills. As mentioned, the cleaning spacer should be in turbulent flow, if at all possible. The supplier of the cleaning surfactant should have performance criteria for the surfactants that show how flow rate and surfactant concentration affect the performance of the spacer. Surfactants and solvents are capable of dispersing or dissolving a certain amount of mud per unit of surfactant / solvent pumped. Careful laboratory evaluation of the spacer systems are required to optimize surfactant concentration and volume required for a given amount of mud, contact time and flow regime. For example, a given surfactant has both a critical concentration threshold and a critical velocity, below which it is simply ineffective for OBM. This relationship, depicted in Figures 3.10 and 3.11, is a necessary part of the information database required to design the best displacement possible for a given completion.

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Wellbore Clean-up

Cleaning Efficiency (%) vs. Contact Time (minutes)

Figure 3.10 Cleaning Index Simulation of a 5 vol% "Surfactant Wash Spacer", pumped at up to 250 ft/min for up to 10 minutes contact. This surfactant contains 0 vol% OBM contamination, thus simulating fresh (i.e., unused spacer). A cleaning index of 1.0 represents 100% clean.

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Wellbore Clean-up

Cleaning Efficiency (%) vs. Contact Time (minutes)

Figure 3.11 Cleaning efficiency of "surfactant wash Spacer” (contaminated with 25 vol% mud) vs. annular flow-velocity at various surfactant concentrations. Top graph is 50 fpm. Bottom graph is 200 fpm.

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Wellbore Clean-up

Chapter 4 Filtration

Filtration can be defined as a process used to remove suspended materials from liquids. In the case of completion fluids, the suspended materials can include weighting agents, drill solids, perforating debris, sand, scale, rust, etc. These suspended materials, if left in the liquid, can change the permeability of the formation. Permeability is a measure of the resistance offered by the rock to movement of fluids through it.

By selecting the proper filtration method, fluids can remain clean and non-damaging andthe process can be done in a cost-effective manner. There are two (2) types of filtration used in completion and workover operations:

1. Depth filtration utilizing recessed chamber plates (Diatomaceous Earth).

2. Surface filtration-using cartridges.

In most cases the combination of these units provides the most efficient filtration package.

Equipment design: Diatomaceous Earth (D.E.) filtration system with downstream double pod cartridge filtration unit which acts as a polishing unit and a guard unit against D.E. bleed through.

• The plate and frame unit should have o-ring gasketed plates to eliminate fluid loss while filtering.

• All drain ports in the drip pan beneath the plates of the filter press should be plugged so all of the filter cake and fluid trapped between the plates will be collected when the press is opened. Fluid can then be salvaged.

• Prior to the regeneration process, proper blowdown with air is required to remove fluid trapped in the filter cake within the recessed chambers of the plates and within the manifold system of the press.

• All filtration units will have an apron running the full length of the drip pan area to above the plates on both sides of the press to eliminate potential spill while the press is opened for the regeneration mode. Any fluid dropped into the drip pan of the press will be pumped (diaphragm) into a MPT tank or other suitable holding vessel. This tank will be checked for reclaimable fluid, which can be decanted into another MPT tank or into the rig’s active system.

• All hoses on the filtration unit should have ball valves that can be closed or opened during operation. This will allow the operator to close the valve at the disconnect point, saving fluid when positioning equipment, rigging up or rigging down. The trapped fluid from the hoses will be evacuated back into the pit system. This will eliminate spillage and offer maximum recovery during the filtration operation. Portable troughs at the disconnect points are recommended.

4.1 Equipment design. Pod cartridge Filter Unit

These units usually are of “dual pod” constructions. They have interconnecting piping for parallel, in series or bypass configuration. The vessels or housings hold the disposable “cartridges”.

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Wellbore Clean-up

The number of cartridges per vessel may vary per manufacturing. This equipment is desirable on lightweight fluids and small inexpensive brine cleanups. Also, the lightweight and small “foot print” makes cartridge filtration more favorable over larger DE units if the cartridge unit can maintain the parameters of filtration. (cleanliness, pump rate, density).

4.2 Principle of Filtration

Filtration is a critical step if we want a well to produce at its full potential and remain on line for a longer period. Although filtering can be expensive and time consuming, the net production can be enough to pay the difference in only a matter of days.

Filtration can be defined as the removal of solid particles from a fluid. Since these particles are not uniform in size, various methods of removal must be used.

Filtration has evolved from the old surface filtering systems with low flow volumes to highly sophisticated systems. Regardless of which system is used, a case for filtering fluid can be made for every well completed, every workover, and every secondary recovery project.

The purpose of filtering any fluid is to prevent the downhole contamination of the formation. Contamination reduces production and shortens the productive life of the well. Contamination can occur during perforating, fracturing, or acidizing, workover, and gravel packing a well. Any time a fluid is put into the well bore with a solid content, no matter how slight; the chance of damaging the well is present.

The following example illustrates the seriousness of formation damage:

In 50 barrels of fluid containing one-half percent solids (1/2% = .005 = 5000 ppm), there are approximately 2426 cubic inches of solids. Since the volume of a perforation tunnel 1/2" in diameter and 10" long is 1.96 cubic inches, the volume of solids in that 5 barrels of fluid could totally plug 1235 perforations.

Consider the effect on 300 ft. of perfs, if only 50 barrels of fluid are lost to the formation. If the volume of fluid is increased and the number of perfs is reduced, this damage is compounded. Without a solids free fluid, the well could literally be "killed."

If the well is to be squeezed, cemented, or acidized, how can the cement or acid penetrate into the perfs or channels if the perfs are full of dirt? How can one tell if the perfs are clean? If the well is filled with clean fluid, the pumps are shut off, and the fluid level does not drop, the perfs are completely plugged. The problem is that one cannot put cement, acid, or anything else into a hole that is already filled with dirt.

If a gravel pack is to be done and contaminated fluid is used as a carrying fluid, the small particles of solids mixing with the sand will take up the pore space between the sand grains, reducing the permeability. The permeability of this mixture is actually less than that of the gravel pack with pure sand particles.

A contaminant in fluid can come in many sizes and forms. Cuttings from drilling operations, rilling mud, rust, scale, pipe dope, paraffin, undissolved polymer, and any other material on the casing or pipe string contributes to the solids in the fluid. At times it is virtually impossible, because of particle size, to remove all of the solids from the fluid, but by filtering, this success factor can be increased 100%.

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Wellbore Clean-up

How clean does the fluid need to be? What size particle do we need to remove? Typically, the diameter of the grains of sand is 6 1/3 times the size of the pore throat, assuming the sand is perfectly round. Particles greater than 1/3 the diameter of the pore throat bridge instantly on the throat and do not penetrate the formation. These particles represent a problem, but one that can be remedied by hydraulic fracturing of the well and blowing the particles from the perf tunnels, by perf washing tools, or by acid. Particles less than 1/10 the diameter pass through the throat and through the formation without bridging or plugging. However, particles between 1/3 and 1/10 the pore throat diameter invade the formation and bridge on the pore throat deeper in the formation. These particles are the ones that cause the serious problems because with the pore throats plugged and no permeability, acid cannot be injected into the formation to clean the pore throats.

Suggested guidelines for the degree of filtration are:

Table 3 Degree of FiltrationFormation Sand Size

(Tyler mesh)Filtration Level

(Microns)20 11.8440 5.4180 2.49100 2.09

4.3 Relationship between Completion and Filtration

The actual process of completion and how it interacts with filtration is as follows:

1. Displacement of drilling mud with Seawater. Here we normally displace all the downhole drilling mud with unfiltered sea or saltwater while rotating the work string slowly to insure complete displacement of the mud. Unfiltered sea or salt water is used in an open loop system. Both straight circulation and reverse circulation have been used during this stage of the process; this decision is usually based on on-site judgment. The advantage of the reverse circulation technique is that it offers low viscosity, high turbulence flow through a smaller pipe diameter to carry particles, to the surface.

During this step (step 1), the bit and casing scraper runs are made through the wellbore to remove mud cake and rust that build up on the tubulars.

2. Assurance of a clean wellbore. When water returns are of the same quality as the water pumped into the well, unfiltered sea or salt water is displaced with filter sea or salt water, again while rotating the work string to assure complete displacement. Filtering down to 2 microns is desirable to remove plankton and bacteria, preventing growth of micro organisms in the bore after completion is finished.

One advantage to initially flushing the wellbore with unfiltered water is that it reduces the filtering time by removing a great percentage of contaminant initially.

At this point the operator starts using clean fluids, the most desirable method of operation being to switch to clean tanks, lines, troughs, pumps and traps, uncontaminated by drilling muds. If this is not possible, the entire existing system should be cleaned of mud. A clean production or work string should be used for completions. When inserting a new string, dope should be applied to the pin end

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Wellbore Clean-up

only, in small amounts, rather than to the box end in large amounts, as excess dope can fall in the hold and plug formations.

3. Displacement of completion fluid. When recirculated sea or salt water is clean, indicating a clean wellbore, a completion fluid is inserted. If possible, it is desirable to run a clean spacer system as an interface between water and completion fluid.

Maintenance of clean completion fluids starts at the dock by assuring that all equipment used to handle completion fluids is clean. Field mixing of brines is not recommended. Delivery should be made in clean tanks. Final filtration when running them downhole is recommended.

4. Perforation. After perforating and washing perfs, the perforation debris and formation sand must be filtered out of the completion fluid to prevent replugging of the perfs and formation.

5. Gravel pack. When perforating is complete and the completion fluid has been filtered to the desired level, the drill pipe is pulled, production tubing is run, and the well gravel packed. These precautions generally result in a stable pack with the desired flow, although there is no ssurance that this will be the case.

In summary, experience has shown that successful completions depend primarily on following a set procedure without taking shortcuts, and on good housekeeping practices. A key element in the entire process is using clean fluids, which is made possible in large part through filtration techniques.

4.4 Cartridge Filtration of well Completion and Related fluids

Oil and gas well drilling and completion processes expose the hydrocarbon reservoir to fluids and solids that reduce its permeability. Permeability is one of the most important properties of the sedimentary rock, or sand, containing petroleum deposits. It is a measure of the resistance offered by the rock to movement of fluids through it. As pores become partially or totally blocked, resistance to flow increases and overall permeability decreases.

Therefore, operations that come into direct contact with the production zone have the greatest potential for causing formation permeability damage. Completion operations fall into this category. These are the activities that prepare the well of production once the well has reached its pre-determined depth, or after the producing formation has been penetrated. Workover and stimulation operations are also examples of direct pay-zone contact activities. While such operations are unavoidable, much can be done to reduce the permeability damaging mechanisms these operations create. Reduced permeability in the producing formation can be the result of chemical or mechanical damage mechanisms. Chemical damage mechanisms are the result of incompatibility of the downhole fluid used with the formation, its connate water or other formation fluids. Mechanical damage mechanisms are the result of the undesirable movement of solids that can 1) weaken the formation, or 2) fill or bridge the formation pore spaces.

While downhole fluid composition varies greatly depending on the operation, water is usually the principal component. Many dissolved or suspended substances are added for density, viscosity, and corrosion control. Salts of sodium chloride and calcium chloride are commonly used to increase the density of completion fluids. Mixtures of calcium bromide, calcium chloride, and zinc bromide are used to produce densities over the entire range of 9. to 19.2 lb/gal. Such high-density completion

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Wellbore Clean-up

fluids may have viscosities between 30 cps and 60 cps and are referred to as heavy "brines." They can cost hundred of dollars per barrel and are filtered for continued use. A dirty completion fluid that contacts the payzone can cause mechanical damage that lowers permeability. Examples include: (1) the dislodging and movement of fine particles away from the formation face which causes clumping, sand (gravel) pack failure, or reduced permeability by the mixing of silts and clays with formation sands, and (2) Plugging of the producing formation by particle penetration into the formation at the wellbore interface (skin effect), or plugging of gravel pack, liner, and screen openings.

Mechanical plugging is the most important cause of formation permeability damage. This plugging can be caused by formation fines, added solids, cement, or other debris suspended in the completion fluid. For this reason, typical or even modified drilling muds with their high solids content should not be placed against a producing formation.

Accordingly, every attempt must be made to use only clean, particle free, completion and workover fluids. A program of clean well site handling practices and proper completion fluid filtration is necessary to obtain the desired level of clarity.

Modern well completion technology has shown that filtration with Diatomaceous earth Systems followed by final polishing filtration with disposable cartridge filters is the recommended method of assuring the clean non-damaging character of completion fluids.

If a large number of undersized solids are present in the completion fluid used while perforating, perforation washing, or gravel pack placement, the overall effectiveness of the gravel packing operation can be compromising. Micron sized particles in the completion fluid can 1) Mix with the gravel resulting in an improper pack that is prematurely plugged, or contains low permeability zones that can lead to disrupted flow channeling and early pack failure; 2) Cause irreversible deep pore plugging of the formation or perforation tunnel; 3) Bridge or plug liner slots or screen openings.

The key to obtaining maximum well productivity with limited time lost to workovers, is to minimize inevitable formation permeability damage. The use of clean non-damaging fluids in the completion and subsequent downhole operations is critical to this end. Final filtration with cartridge filters is a vital step to achieving reproducible non-damaging completion fluid clarity.

Each field, formation, and well site has its own unique characteristics and conditions. These include reservoir rock permeabilities, pore sizes, connate fluid composition, downhole pressures and so on. These vital conditions dictate the brine composition and level of clarity needed. This in turn determines the level of final cartridge filtration needed to achieve the fluid clarity level required.

Research indicates that particle sizes that are one-seventh to one-third the mean pore size of the rock formation will normally not damage the formation. Low permeability formations can have pore sizes around 10 microns in diameter. Accordingly, particles smaller than 2 microns are thought to be non-damaging in low concentrations. Filtering to the 2 micron level should provide adequate protection for any formation. Five to ten micron filtration is the maximum advisable final filtration level.

Disposable cartridge filters of depth or surface filtration type are used alone, in combinations (series), or in tandem with other types of pre-filtration equipment. When very large particles or high

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Wellbore Clean-up

solids concentrations are present, conventional solids control equipment may be used as pre-filters if they are thoroughly washed and cleaned prior to use.

In large volume systems (5 to 10 bpm), a filter press (plate and frame or vertical pressure leaf) using a filter aid (D.E.) precoat can be used as the prime filter. Cartridge filters are used downstream of the large filter press to catch material that bleeds through the dressing medium, remove passed particles from faulty or eroded precoat, and provide backup fail-safe trap filtration. Only cartridge filters can assure the desired absolute particle size filtration efficiency.

Two factors dramatically influence cartridge filter economics; they are the size of the smallest particles to be removed and the concentration of the particles in the fluid. Finer filters are more expensive, and higher dirt loads shorten filter life requiring more frequent replacement. The level of brine clarity desired is therefore an economic decision that requires an understanding of depth and surface cartridge filter characteristics.

Fiber-wound depth filters are designed to capture particles within the tortuous matrix of the filter media itself as well as on the filter's surface. The filter media matrix contains a broad pore size distribution. These openings decrease in size in the direction of fluid flow from the outside to the inside of the filter. This graded pore density allows for the capture of larger particles near the surface, and ever-finer particle capture toward the center. This design concept is similar to the trapezoidal or "wedge-shaped" profile of well screen and liner slot openings.

Fiber-wound depth filters are typically made to remove most of the particles delivered to it of its rated micron size or larger. They work best when the flow rate per filter and the fluid viscosity is low. Since particle removal is not always total, and is somewhat dependent upon operating conditions, these filters are also said to provide "nominal" filtration.

Depth filter cartridges provide an economical filtration alternative when the completion fluid requires significant solids removal, but not complete clarity. Used in this way, depth filter cartridges provide adequate brine quality for many sites or prefilter protection to extend the life of more expensive absolute rated surface filter cartridges.

The optimum filtration system design, including the type of cartridge filter used (depth or surface), can vary from well site to well site. If past experience or reservoir sensitivity studies indicate adequate protection with less expensive 2 micron, 5 micron, or 10-micron depth filter cartridges, then more expensive absolute rated cartridges are not necessary.

Where the characteristics of the solids to be removed are largely unknown or critical conditions and maximum protection of the expensive non-damaging heavy brine is vital, then absolute rated surface capture filter cartridges are a must.

Surface type cartridge filters are designed to capture particles on the large surface area of the filter media. The filter acts like a screen or sieve with a narrow distribution of fixed pore sizes. Since the pore sizes are fixed and controlled, absolute particle size removal efficiency can be assigned to the filter. This allows the completion fluid to be reliably filtered to remove essentially all particles of a given micron size and larger.

The filter media is relatively thin and highly permeable, allowing it to handle much higher viscosity brines than similar rated depth filters. Also the filter area can be ten times greater than

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depth cartridges permitting higher flow rates and much greater dirt holding capacity than depth cartridges.

Over-filtering can be wasteful, but inadequate filtration can be far more expensive and dangerous than filtering too much. It is always cheaper to plug the filters than the well itself.

Once the final filtration requirement is established, the goal becomes one of optimizing a filtration system design. This involves putting together a properly sized and operated system of prefilters and final filters to meet the filtration efficiency objective at the lowest operating cost. This is best accomplished by working with a representative of a reputable cartridge filtration manufacturer that can offer a complete line of absolute rated surface filters, nominal rated depth filters, pressure vessels (pots), micron ratings and materials of construction.

Using clean, compatible, non-damaging completion fluids can help prevent reservoir permeability impairment, help to maximize well productivity, and reduce stimulation and workover time and cost. Cartridge filtration is the most practical way to achieve the necessary clean non-damaging character of these fluids.

4.5 Filtration System Guidelines

1. Flow Rates

Filter life is longest at low flow rates. As a guide, optimum flow rates should not exceed .5 to .75 GPM per square foot of filter area. Thirty inch depth filters should be operated at 1.5 GPM or less per filter for maximum life and efficiency. Forty inch pleated surface filter cartridges can be operated at flow rates from 7 to 20 GPM based on micron size selected and filter area. Systems should be sized to handle maximum flow rate conditions plus 10%. Filters should be changed before differential pressure reaches 40 psi.

2. Serial Filtration.

Series filtration will increase the life of the filters. A 10 or 30 micron absolute prefilter will extend the life of more expensive 2 micron absolute final filters. When depth type cartridges are used, 25 to 50 micron filters are generally effective prefilters ahead of 2 micron to 5 micron final filters.

3. Sealing Filters are useless if the fluid bypasses around a poor seal. Filters are available with positive piston type double O-ring seals. Threaded closures are recommended for depth type cartridges. Depth cartridges are available with a factory attached spring assembly to prevent bypass. These cartridges are available in disposable cage assemblies as well.

4. Housing Design

Filter housings should be manifolded in groups of 2 or 3 with piping to allow series or parallel combinations. This will enable:

(a) Series filtration through the prefilters and then final filters.

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(b) Parallel filtration when high flow rates are needed.

(c) One housing to remain on standby with clean elements for rapid changeover and no downtime.

4.5.1 Maximum Flow rate

Table 4 - 16 element Filter Housing characteristics16 Element Filter Housing

Micro Size Gal/Min Balls/Day1 96 32493 144 49375 240 822910 288 987425 336 1152050 384 13156

Table 5 - 20 Element Filter Housing characteristics

20 Element Filter HousingMicro Size Gal/Min Balls/Day

1 120 41143 180 61745 300 1028610 360 1234325 420 1440050 480 16457

4.5.2 Sources of Solids In "Clean Fluids"

1. The water base fluid itself obtained from rivers, bays, or open sea can contain bacteria, sediments, and plant or animal matter.

2. Impurities contained in some sacked, dry salts used in making brine.

3. Particulate matter from surface pits, tanks and tubulars such as mud cake, rust, scale, pipe dope and paint chips.

4. Iron oxides or other chemicals precipitated from solutions containing dissolved oxygen that are circulated at elevated downhole temperatures.

4.5.3 Weight and Volume of Solids in Dirty Completion Fluid Rock formations make excellent depth filters. A formation exposed at the wellbore to the pressurized flow of dirty fluid will filter the suspended particles from the fluid. Particles will penetrate the pore spaces as well as collect on the surface until an impermeable cake is formed. Figure 2 shows that if 300 barrels of a 12 ppg completion fluid with 1000 ppm (0.1%) of contaminant is pumped downhole, a total of 150 pounds of solids will be delivered to the formation. Assuming an average contaminant specific gravity of 2.4, 150 pounds of solids would occupy about one cubic foot of volume. This is the approximate volume present in an annulus that is 6 inches

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wide and 2 feet long surrounding a 7-inch wellbore in a formation of 30% average porosity (Figure 3).

4.6 Types of Filtration Units

1. Cartridge Filters

There are various types of cartridge filters. The commonly used fiber cartridges are relatively inexpensive, but they are not designed for backwashing and are normally discarded when they become plugged. These filters must be changed very often, requiring additional labor costs. Ceramic and plastic filter cartridges are theoretically capable of being backwashed. On multi-cartridge units, adequate cleaning of all cartridges by backwashing the entire unit is normally impossible because of flow channeling through a few cartridges. However, if the cartridges are removed from the filter and washed individually, cleaning may be effective. Again, there are additional labor costs to do this cleaning. Cartridge filter is illustrated in Figure 4.1.

Figure 4.1 Cartridge Filters

2. Diatomite Filters

Diatomite filters consist of a layer of diatomaceous earth about 1/8 inch thick supported on a septum or filter element. The thin precoat layer of diatomaceous earth is subject to cracking and must be supplemented by a continuous body feed of diatomite. The problems inherent in maintaining a perfect film of diatomaceous earth between filtered and unfiltered water have restricted the use of diatomite filters. Diatomaceous earth filters normally require greater investment and operating expense than conventional pressure filters.

3. Downflow Sand Filters

Rapid filters operate at about 30 times the rate of slow filters, which require large land areas to handle the same volume of water. Slow sand filters are no longer used because of prohibitive capital and operational costs. Slow filters are often cleaned by scraping a thin layer of media from the

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Wellbore Clean-up

surface of the bed, washing it, and returning it to the bed. Rapid filters are cleaned in place by reversing the flow of water through the filter to expand and scour the media. Hydraulic backwashing may be assisted by directing jets of water into the expanded media by stirring with mechanical rakes or injecting air into the bed before or during backwashing. Diatomaceous filter is illustrated in Figure 4.2

Figure 4.2 Downhole sand filter

4.6.1 Multi-Media High Rate Filters

Multi-media high rate filters are generally pressure filters which utilize layers of different types of filter media. Almost all high-rate filter media are granular solid materials of reasonably uniform size.

Among the media which are commonly used are sand, gravel, anthracite and garnet.

The filters may be operated in several different modes, viz, downflow, upflow and center injection with radial outward flow. Figure 4.3 shows a typical multi-media filter.

Figure 4.3 Multi-media high rate filter

4.6.2 Tubular Filter

Back washable tube filters may be utilized with or without a filter aid such as diatomaceous earth. In either case, they offer many of the advantages of cartridge and bag type filters without the necessity for continually replacing filter elements. Figure 4.4 illustrates a typical tubular filter

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Wellbore Clean-up

configuration. The tubular elements may be of a variety of different sizes and make-ups. Figure 11 illustrates the variety of available elements.

Figure 4.4 Tubular Filter

Tubular filters offer low cost construction and high hydraulic capacity. Filter aids, such as diatomaceous earth, may be used in much the same manner as with plate and frame filters. Figure 12 illustrates the complete tubular filter system with filter aid capability. Properly designed tubular filters can provide some significant operational benefits during the backwashing cycle. As illustrated by Figure 5, during the normal operational mode, the liquid level remains at approximately the outlet level of the filter. When the differential pressure measurement indicates that the filter is ready for backwash, the outlet valve is closed. Continued pressurization by the feed pump forces filtered liquid into the dome, thereby compressing a volume of air or gas. Upon reaching the desired pressure, the inlet valve is closed and the drain valve is opened, allowing a sudden surge of liquid. This sudden, high velocity flow cleans the filter element with only a minimal loss of fluid (typically 2 gallon/ft2).

Tubular filters are utilized in a variety of applications including completion brine filtration, condensate recovery, refining, and pollution control, sugar syrup filtration and brewery filtration. Figure 13 illustrates a tubular filter.

4.6.3 Plate and Frame (Press) Filters

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Wellbore Clean-up

Plate and frame filters (Figure 4.5), have the advantages of low cost, near indestructibility, and ease of internal inspection. They have the lowest volume-to-area ratio, which makes them the most efficient for the washing of filter cakes. This also gives them the smallest unfiltered portion remaining at the end of the cycle.

Figure 4.5 Plate and Frame (Press) Filters below the Cartridge Filers

They are normally used with a filter aid, such as Diatomaceous earth (D.E.) and can reduce the average particle size to less than 1 micron with high flow rates and high solids loading. Diatomaceous earth is composed of fossil skeletons of microscopic water plants called diatoms. This material tends to pack well and form a highly permeable, stable and incompressible filter cake. The composition of the D.E. is most silica, which is insoluble in anything except hydrofluoric acid. Diatomaceous earth is available in different grades and different median pore sizes.

The flow of dirty fluid with D.E. enters at the center of each plate and the filtered fluid exits at the corners of the inner chamber of each plate. When a filter cake has been formed of sufficient thickness, the cycle is terminated and the filter is cleaned and precoated again. Recleaning and precoating the press usually takes 20-30 minutes, depending on the number of plates. An experienced operator is required to select the proper diatomaceous earth material for use in a specific job and to load the proper amount of D.E. into the unit during the job.

A cartridge filter unit is necessary downstream from the D.E. filter to catch D.E. that often comes through the unit.

There are several methods of removing solids from a fluid. These are Diatomaceous Earth (D.E.) and Cartridge Filtration. Each individual job is approached from the standpoint of determining the customer's need and then designing a filtration system around that need. Some basic facts regarding brine filtration are:

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Wellbore Clean-up

• D.E. Filtration is used when less than 5-micron fluid is required for well usage.

• Cartridge Filtration is used when 5 micron or greater fluid is required, or if the unit will be self-operated by rig personnel.

• In a gravel pack operation 95% of the operators will use D.E. Filtration.

• Cartridge units are excellent for use in older well workover operations or oil well completions.

• For fluid that is 8% solids-laden or greater it is suggested to first filter with a larger

micron rated cartridge. Then follow up with a D.E. unit. This procedure will save on rig downtime, which will offset the cost of getting two different filter units.

• If there is a possibility of polymer contamination, then only a D.E. filter will work. D.E.

filtration is depth (cake) filtration and cartridge filtration is surface filtration (minor depth).

• When a flow rate of 4 bbls per minute or more is needed, a D.E. Unit should be used. An example would be using a D.E. Unit when an operator will be washing perforations.

• When slower rates are acceptable, then a cartridge unit will be more economical.

• The type of fluid and its weight are factors in the decision to use a Cartridge Unit versus a D.E. Unit. With fluid that is 15.0 ppg or less, a cartridge unit will provide satisfactory performance.

• With fluid that is 15.1 ppg or more it is suggested that a D.E. Unit be used.

• All fluids need to be clean, but fluids containing zinc need to have special consideration.

• The viscosity of the heavier fluids makes filtration easier with a D.E. system.

4.7 Filtration Process

1. Fill tanks with seawater or saltwater to be used for displacing mud. Displace all downhole drilling mud with unfiltered sea or saltwater while rotating the work string slowly to insure complete displacement of the mud. Maximum benefit is achieved by using reverse circulation in all displacing operations.

2. Continue displacing mud with sea water or saltwater until water returns are of the same quality as the water pumped into the well, displace sea water or saltwater with filtered sea or saltwater, while again rotating the work string slowly to insure complete displacement. Always use Micron elements when filtering seawater to remove plankton, gelatinous bacteria and fines.

3. If possible, run oil soluble viscosified "pill" of 20-30 barrels as an interface between seawater and filtered completion fluid.

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Wellbore Clean-up

4. Dispose of seawater and viscosified "pill". Due to high solids content, this fluid will contaminate a clean system. It is also uneconomical to filter.

5. Fill clean tanks with clean filtered completion fluids.

6. When circulating completion fluids, return across shale shaker with 300/350 mesh screens and through Brandt or Sweco unit with 425 screen if available. Then discharge into dirty fluids tank. This step will reduce particle contamination to the 50-100 micron range, or less. It will also speed the filtering process plus save money by reducing the number of filter cartridges necessary for cleaning the fluid.

7. Take suction going to filters, from near top of dirty fluids tank. Do not take suction from or near bottom of dirty fluids tank.

8. Filter fluid at 50 micron continuously during underreaming, drilling out cement, plugs

and scraping casing.

9. When solids contamination is above 100 ppm always use 8-cone unit ahead of filters.

10. For efficiency and economy when cleaning up dirty fluids, with cartridge filters always circulate and stage down, i.e., 50 to 20 to 10 to 5 micron range, until desired micron rating and fluid quality is reached.

11. Filter continuously during gravel pack and reversing out.12. Always use filter elements, which are recommended for and compatible with your fluid.

4.8 Clarity

Clarity is considered by many engineers to be the most important measure of efficiency in filteraid filtration. So many things affect clarity – both favorably and adversely – that only general principles can be stated. A high quality filteraid is most important for uniform results day after day. Selection of the particular type and grade of filteraid having the correct particle size and distribution is a major factor. After these come many considerations such as the quantity of filteraid to be used in fixed bed, body-feed, and rotary precoat filtration; the flowrate needed to meet plant production schedules; the equipment and general filtration condition; and others. All of these can best be resolved by tests using the actual liquid to be filtered. Filteraid filtration gives practical solid removal efficiencies, but not absolute (100%).

Clarity measurements involve the most difficult aspects of filtration technology. Visual evaluation of filtrate clarity is only semi-quantitative at best; critical evaluation requires instrumental measurement.

The significance of accurate clarity measurement is readily seen when evaluating a series of any type of filteraid. For example, while filteraid "A" may have 90% of the clarification efficiency of filteraid "B" in a raw sugar solution, the relative performance in a pectin system may be only 60%. Moreover, the relative clarification of two filteraids with respect to the same liquid may change markedly depending upon the conditions of the test. Because of the many variables involved, which can influence results to an enormous degree, it is imperative that comparative tests duplicate, as nearly as possible, actual plant conditions.

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Wellbore Clean-up

While it is possible to calculate the average pore size of a filter cake, filtration engineers have known for some time those particles much smaller than the calculated pore throat diameter are readily retained by diatomite and perlite filteraids. Under controlled conditions filtration engineers prepared suspensions of uniformly sized particles (0.11 to 10.0 micron range) and conducted laboratory filtration tests that enabled them to determine the exact size particles removed by each grade of Dicalite diatomite filteraids. It should be understood that filteraid filtration gives practical solid removal efficiencies but not absolute (100%).

4.8.1 Brine Sample Evaluation: Procedure for Determination of Clarity

This procedure concerns standard methods for the evaluation of a representative type sample of a clear brine. Concentration, particle size distribution, and type of solids present may affect the utility of the brine. Minimum and/or maximum limit on contaminating solids is between the supplier and the user. Sampling of brines is complicated because of the possible presence of large particles of trash; the instability of certain dissolved ions, such as iron; and the ubiquitous influence of a variety of minerals, gunks, and residues on brine quality. Fluids weighted with calcium carbonate or other agents are excluded from this procedure.

Brine clarity is important in the following determinations:

• Formation damage potential.

• Isolation of a source of contamination in the course of manufacture, transport, storage or well site use.

• Provide a basis on which specifications or limits can be placed on the concentration and/or type of solids found in water or brines.

The primary objective of the test is to provide understanding and guidance on a method for the generation of a well-by-well calibration curve that relates turbidity, by use of a nephelometric turbidity unit, to solids concentration in a known density brine using the actual wellbore solids for a given well. Coarse matter greater than 200 mesh (74 microns) is excluded as a turbidity factor. Subsequent identification of the type of solids is an added feature of this procedure when it is desired to do so.

The procedure recommended here can only place a relative value on the presence or absence of solids occurring in a particular sample. It should also be cautioned that in transferring brines from one tank to another or perhaps sampling during the course of several downhole displacements, the turbidity and type of solids will, in all probability, vary significantly from one sample to another. It is extremely important, therefore, to be aware of the actual event that a particular brine sample represents.

This procedure may not be applicable in the presence of fluid loss additives or thickeners.

In most cases, NTU (nephelometric turbidity units) values will not be affected by tinted or water-soluble colored brines. However, caution is advised for exceptions to this general rule.

4.8.2 Equipment and Materials for Field Testing

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1. Four-to-eight-liter (one to two-gallon) clean plastic or glass containers with tight-fitting closures - no metal.

2. Labels or wire-on tags for recording sample information.3. Marsh funnel with standard, top-mounted 14-mesh screen.

4. U.S. 200-mesh, woven sieve or API sand content test set in good condition.

5. Standard mud balance.

6. Membrane filter set consisting of:

• 47 mm. filter holder• Side-arm vacuum filtering flask.• Vacuum source.• 47-mm. membrane disc filter (nylon).• 0.45 micron pore size.• 47mm, 5-micron borosilicate microfiber glass prefilter.• 500 ml. graduated cylinder.

7. Nephelometer (ratio turbidimeter) – minimum specifications: 0 to 10, 0 to 100, and 0 to 200 NTU; ±1 percent of full-scale precision; 0.02 NTU sensitivity; field portable.

4.8.3 Sampling methods and Sampling Points

Mixing Plants: Fully circulated sample from the low-pressure line (no surface sampling).

Transport Operations :

• Trucks – Flow at exit valve for about one-half of the volume of the load and then sample.

• Supply Boats – Thief a sample before off-loading for use in density, clarity, and crystallization point tests.

Rig Site:

• Specified Rig Tank – Sample at low-pressure line if available.

• Flow Line.

• Collect a liter of representative sample. Divide the sample. One sample is for well site turbidity analysis using a nephelometer. The second sample is to be forwarded to a laboratory facility for gravimetric analysis. The sample should first be passed through the 14-mesh screen of a funnel marsh to remove macroscopic contaminants. Note type of materials retained on the screen, if any.

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Wellbore Clean-up

• Make an initial determination of the particle size and concentration of solids in brine by pouring 500-ml through a 200-mesh woven sieve (the screen in the API sand content kit may be used if desired) into a 500-ml graduated cylinder. Let stand for several minutes to allow solids to settle or float.

• Scoop out floating solids. Decant the remaining sample containing dissolved and suspended solids, being careful not to transfer coarse solids that have settled out.

• Reserve a minimum of 100 ml of non-filtered brine for serial dilution.

• Filter the remainder of the sample through a 0.45-micron filter until a clean sample is obtained. A minimum of 50 ml filtered brine is needed. Use the filtered brine for serial dilution.

• Calibrate NTU meter using manufacturer's standards. For most NTU meter’s, sample size is 20 ml.

4.8.4 Laboratory Gravimetric Test

A known volume of fluid is passed through three pre-weighed 47-mm. discs. Each disc is rinsed with distilled water, dried, and reweighed. The total suspended solids of the fluid (mg/l) is determined from the weight gain per sample volume. Triplicate samples should be run and results averaged.

4.8.4.1 Equipment and Materials

• 47 mm. 0.45-micron nylon disc and 47 mm, 5 micron Millipore borosilicate glass disc.

• Forceps.

• Analytical balance.

• Oven.

• Desiccator.

• Fritted discs, funnel, vacuum flask, and funnel clamp.

• Vacuum pump (hand pump is suitable).

• 1-liter graduate.

• Sample bottle (minimum 100 ml.).

• 50-cc syringe.

• Distilled water.

• Petri plates.43

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4.9 Turbidity

Turbidity is defined as the "expression of the optical property that causes light to be scattered and absorbed rather than transmitted in straight lines through the sample." This scattering and absorption is caused by the interaction of light with particles suspended in the sample media. Suspended solids including silt, clay, algae, plankton, microbes, organic matter, and other fine insoluble particles can cause turbidity. Particles interfering with light transmittance cause the sample to take on a hazy or cloudy appearance. Simply put, turbidity is the opposite of clarity.

Turbidity originally was determined by measuring the depth of a column of liquid required to cause the image of a candle flame at the bottom to diffuse into a uniform glow. This was known as the Jackson Candle Turbidimeter. Calibration was based on suspensions of silica from Fuller's or diatomaceous earth. The turbidity caused by one part per million (PPM) of suspended silica was defined as one Jackson Turbidity Unit. This method measured the attenuation of light transmitted through the sample. This attenuation is too small at very low turbidities to be measured reliably, thus, severely limiting the Jackson Candle's application.

Turbidity usually is measured today by applying nephelometry; a technique, which measures the level of light, scattered by particles at right angles to the incident light beam. When light hits a particle, the energy is scattered in all directions. The scattered light level is proportional to the particulate concentrations and can be measured by an electronic photodetector. Photodetectors can be made with extreme sensitivity to low light levels to allow measurement of low turbidities.

Turbidity of a liquid is important for many reasons, depending on its use. Besides the aesthetic appeal of crystal-clear water, low turbidity is important in drinking water tominimize water-borne pathogens. Turbidity in water can be caused by harmful organisms, particles that feed them or particles that can shelter them from disinfecting processes. To assure a safe drinking water supply, water plants are required by law to maintain a uniform low turbidity in their finished product. In other liquids, turbidity can be caused by particulates detrimental to the end use, or perhaps by particles that are vital ingredients of a product. In either case, turbidity can be used as a quality control measure to monitor the efficiency of the treatment or manufacturing process.

Turbidimeters are calibrated in Turbidity Units (TU). Originally, one TU was equal to the turbidity caused by one ppm of suspended silica. The Nephelometric Turbidity Unit (NTU), the most common unit in use, provides reference to the nephelometric measurement technique. The NTU can differ from the Jackson Turbidity Unit (NTU) that was used with the Jackson Candle Turbidimeter, which was standardized using a suspension of clay or some other natural material.

Formazin is the material used today as a primary turbidity standard. Formazin can be synthesized in the laboratory with 1% or better repeatability. Serial dilutions of formazin are universally accepted now as primary standards for calibrating turbidimeters.

Secondary standards are available for routine calibration of turbidimeters. They are more convenient and economical than formazin for day-to-day calibration checks. Dilute formazin

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solutions are not stable and must be prepared fresh daily. Secondary standards are much more stable and can be checked periodically against formazin to assure accuracy.

Three major features of a turbidimeter affect its response to a sample. They are light source, the photodetectors, and the physical configuration between the photodetectors and the sample cell (optical geometry). Different light sources have different spectral outputs; the most intense color they produce varies. Photodetectors also have different spectral characteristics; some are sensitive to near infrared while others have peak sensitivity to the ultraviolet band. In addition, optical geometry between detectors and the sample cell affects factors such as sensitivity and linearity. As a result, turbidimeters may respond differently to a sample, even though they are calibrated on the same primary formazin standard.

Turbidity levels rise and fall as the suspended solids concentration increases and decreases. However, the amount and color of light scattered by any particle is dependent on the particle's size, shape, composition, and refractive index. Solutions of equal suspended solids concentration but different composition may not scatter the same amount of light. Thus, turbidity relates to suspended solids, but the relationship can not be quantified.

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Chapter 5 Mechanical Assistance5.1 Wellbore Clean Up Tools

During wellbore displacement some time it is no possible to remove from the well certain types of cutting and debris, specially those one with high gravity and complex shapes; to solve this problem mechanical wellbore cleanup assistance was introduced. In mechanical wellbore cleanup assistance tools such as: casing scraper, brushers, downhole debris filter, jetting tools, junk basket, and magnet assembly are run in hole to enhance chemical clean up methods efficiency for wellbore assurance.

5.1.1 Casing Scraper

Casing Scraper (see figure 5.1 is used to remove mud or cement sheath, imbedded bullets, perforation burrs, rust, mill scale, paraffin and similar substances from the inside walls of the casing.

The importance of keeping this vital "working surface" clean and smooth is because all subsequent operations in the well are affected in one way or another by the condition of the casing ID. An imbedded bullet or sharp burr can damage a swab cup or packing element; less-than-full calculated inside diameter can be responsible for premature set of close-tolerance tools; and hardened rotary mud or a thin cement sheath left after drilling out following a cement job may prevent the slips of a pack-off tool from engaging the wall of the casing.

Reasons for Casing Cleanup:

• Completion Fluid Contamination • Invasion Of Mud-Cake Particulate Into Formation Erosion Of Downhole Tools From Mud

Solid • Wireline Tooling Damage And Contamination • Cementing Efficiency • Perforation And Fracpack Damage

Features/Advantages

• Rugged Construction. The body of the Scraper is machined from solid bar stock, and blade blocks are of case hardened steel for absolute maximum ruggedness and strength.

• Rotating or Reciprocal Action. The Casing Scraper operates successfully either when rotated or reciprocated vertically on drill pipe or tubing. It can also be run on cable-tool drilling line with jars and sinkers when ordered with a cable-tool joint pin up.

• Cannot "Screw" Down During Rotation. The angle and direction of shear of the scraping edges of the blades are such that the cannot "screw" down past burrs as it rotates

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Figure 5.1 Casing scrapers with Rotating or reciprocal Action.

Operation

For removal of cement sheath, the Scraper should be installed between the drill bit and the drill collar so that both the drilling-out and the sheath removal can be accomplished at the same time. It is good practice to maintain circulation while these operations are being conducted. The Scraper should be run completely through the perforated section without rotation, then pull back up and make a rotary run through the section. Casing Scrapers can be operated without rotary equipment by simply running completely through again. If the perforation density is relatively high, it is a good policy to rotate the tubing a quarter of a turn with tongs.

5.1.2 Casing Brusher

The Wellbore Specialties Casing Brush Tool (see figure 5.2) is a mechanical aid for all wellbore cleaning operations that can be run as a stand alone device in most drilling or completion operations and is fully compatible with the entire line of Wellbore Specialties Clean-Out Tools.

Figure 5.2 EZI-Change Casing Brush

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Wellbore Clean-up

5.1.3 Riser Brush

Riser Brushing Tool (see figure 5.3) are designed to clean the inside of marine drilling risers more effectively by scouring, scraping, wiping and retrieving debris from it, prior to running completions. The tools can be run in the drill string to supplement chemical clean-up methods and augment scrapers that may already be present.

It was designed to clean riser systems more effectively by scouring, scraping, wiping and retrieving debris from the riser.

Features

• Removes cement and debris from riser internal surfaces• Flow-by channels between brush pads allow easy passage of clean-up fluids• Bristles cut to suit client requirements• Manufactured from chemically resistant materials• Can be run with high efficiency jetting tools and inspection camera systems• Available with stainless steel, carbon steel, nylon and poly brushes• Easy to redress

It is recognized that only relatively low annular velocities between drill pipe and riser are achieved, even at high pump rates. As a result, loosened debris is often not circulated out and could fall down the well. To catch this debris a Junk Trapper® has been built into the Bristle back.

Table 6 Clean Well™ Riser Bristle Tech™ Parameters

Clean Well™ Riser Bristle Tech™

RobustIntegral mandrelSmooth inner boreNo internal connections or upsetsBig bore designNon-Rotational (independent from mandrel)360º casing coverage per bristle sleevesection (two bristle sleeve sections) 4145 or 4330 material constructionAdaptable ring systemsEnormous flow area (ideal for 40+ bpmboosting) >100 in² of flow areaFlow area around outer diameter of tool and under bristle sleeves

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Wellbore Clean-up

Designed with API stress relief grooves onconnections and bore back radiuses onmandrelStress concentration managementNo external bolts

Figure 5.3 Riser brush

5.1.4 Scraper/Brush tool

Scraper Brush (see figure 5.4) is the most technically advanced and robust casing cleaning tool available to the Oil and Gas Industry today. Design features make it ideal for removing rust, mill scale, cement stringers, paraffin and other foreign debris from inside walls of casing. The combination is lead by scraper blades acting on the most persistent and stubborn contaminants followed by brushes to ensure no debris remains, polishing the casing ID. Tool and packer malfunctions will be a thing of the past, hastening clean up time and saving valuable rig time and money.

Features

• Utilizes two tools in one to achieve maximum surface cleaning performance

• No additional stablizer rental is required. Dynamically designed stabilizers protect the brushes from premature wear and the scraper blades from abuse while rotating

• The entire tool is machined from solid bar stock 4145 heat treated SAE material. To give maximum strength and reliablity, absolutely no casting is used

• Specialized tool joint connections can be machined to fit customer specific job requirements

Figure 5.4 Scraper/brush

5.1.5Jetting Tools

Jetting Tool (see figure 5.5) is designed to be run in a cleanup string where it is desirable to jet the riser blowout preventers (BOPs) and wellhead areas. This mechanical device enhances the

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Wellbore Clean-up

cleaning efficiency of the other cleanup tool assemblies by providing jetting action in the BOP stack, marine riser and/or the casing/wellhead area.

The BOP stack has several areas that are very hard to reach and require a combination of mechanical and chemical cleaning technology to remove undesirable solids and other debris from the interior of the stack, i.e., Annular Blowout Preventers and Ram Blowout Preventers. These “drilled and mud solids” can cause the BOP stack to malfunction if they are not removed. Improper working BOP stacks can lead to equipment failure resulting in flow at the surface, rig fires, underground blow outs and pressure kicks during drilling or workover operations.

Jetting Tool is placed in areas where debris is not easily accessible to scrapers, brushes or magnets, and where no metal-to-metal contact is desirable.

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Wellbore Clean-up

Figure 5.5 Speed well Jetting Tool

5.1.6 Downhole Debris Filter This powerful tool removes metal/solids from wellbore with special debris filter and retention chamber. Provides reverse circulation of downhole assemblies without having to reverse from surface, saving valuable rig time. One of downhole debris filter worth mentioning is junk basket, which is used in conjunction with washing/ jetting of the BOPs. The tool is normally run below the jetting wash tool during a short trip to clean the BOPs.

Figure 5.6 Roemex Junk Basket

5.1.7 Magnet Assembly

Magnet assembly is a magnetic downhole sub for use in wellbore cleanup operations. The tool has been designed to meet the demands of complex wellbore cleanup operations, and is suited to

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Wellbore Clean-up

current practice when performing pre-completion/drillstem test (DST) and workover cleanups. The tool is run as an integral part of the drill string during cleanup to collect ferrous metal debris and remove it from the well. It can be run as part of most drilling/milling/polishing assemblies, and can be rotated and reciprocated without fear of damage to casing or tool.

The magnets are strong enough to collect ferrous metal debris while going into the hole. Pulled out of the well, the magnets collect any remaining ferrous debris which was not circulated out to surface. The stabilizer sleeves provide stand-off and prevent the captured material from being dislodged by pipe movement.

Figure 5.7 Roemex magnet tool

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Chapter 6 Results and Discussion

In this chapter we are going to analyze some services companies’ wellbore clean-up operations. These analyses will be done in term of wellbore clean-up time, efficiency and cost. In order to simply our job and let you to get a better understanding of this analyze, I am going to do this mainly in form of chart, tables and son on.

we will analyze wellbore clean-up operations that have been done in Congo basin in blocks 14, 15,17 and 18 operated respectively by Chevron, Exxon Mobile, Total and BP. The services companies that are working in these blocks are Ser.1, Ser.3, Ser.2 and Ser.4 respectively. All those blocks are deep water blocks (see Figure 6.1); perhaps someone may ask why deep water’s wellbore clean-up projects analyze? My answer is, it is because actually in oil industry we are going toward deep water technology because it is estimate that more than 86% percent oil resources are found in deep and ultra deep water environment as it was said in the 2nd Regional Deep Water Offshore West Africa Exploration & Production Conference (DOWAC); that is why I have chosen these blocks and analyze their wellbore clean-up operations. I am going to analyze the wellbore clean-up procedures in block 14 the701, BBLT and Pride Venezuela Rigs, in block 15 the Xikomba, Kizomba A and B projects, in block 17 Dalia and Rosa Projects and in block 18 the Greater Plutonio project. I will do a thorough study of wellbore clean-up procedures only for block 14 which is the one that belong to the company that I am working for, and other blocks I will only compare their results with that one of block 14.

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Wellbore Clean-up Figure 6.1 Congo basin blocks

6.1 M-I SWACO Wellbore Clean-up Operations in Block 14

Ser.1 is a solution provider within drilling, wellbore productivity, production technologies and environmental process and services. This service company is working for Chevron since 2002; they are providing drilling fluid, waste management and wellbore clean-up services.

Last year Ser.1 acquired Specialized Petroleum Services Group Limited (SPS) of Aberdeen. SPS is a global market leader in wellbore clean-up solutions. With its primary focus on the offshore Eastern Hemisphere market, SPS International offers a comprehensive line of patented clean-up tool technology as well as its industry recognized WELLBORE ASSURANCE process. The company’s products and services are designed to minimize damage to the reservoir face and deliver a clean, unobstructed well bore for maximized completion efficiency.

Now we will describe Ser.1 clean-up operations times that have been done in 701 rig (Landana, Lobito and Benguela fields), BBLT rig (Benguela and Belize fields) and Pride Venezuela rig (Landana and Tombua Field). This description shows the time that each clean-up operation takes to be done at rig site. The wellbore clean-up operations described in the chart (Figure 6.2-a) are:

• Make up and Run in hole clean-up bottom hole assembly (RIH clean-up BHA)

• Displacement kill, choke and booster lines

• Circulate pills and seawater

• Displace clean-up train with seawater to 50 NTU +/-

• Displace to filter brine

• Debris removal

• Pull out of hole and lay down Clean-up bottom hole assembly (POOH & L/D clean-up BHA)

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Wellbore Clean-up

Figure 6.2-a Some SASBU’s rigs wellbore clean-up times

Figure 6.2-b BBLT, 701 and Pride Venezuela rigs wellbore clean-up total times

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Wellbore Clean-up Total Times

PV47.0737%

70134.8727%

BBLT46

36%

Block 14 Avarage Clean-up times

0

2

4

6

8

10

12

14

16

701 PV BBLT

Clean-up Operations

Tim

es (

Hou

r)

M/U & RIH Clean-up BHA

Diplacement Kill,Choke andbooster Lines

Circulate Pills and seawater to 50-20 NTU +/-

Displace Clean-up Train w/Seawater

Displace to Filtered Brine

Debris removal with Junk Basketor Magnet

POOH & L/D Clean-up BHA

Wellbore Clean-up

According with chart in Figure 6.2-a we can see that the clean-up operations that are taking more time in 701, Pride Venezuela and BBLT rigs during wellbore clean-up process are: POOH clean-up BHA, RIH clean-up BHA, displace to filter brine and displace clean-up train with seawater, so we are going to focus mainly on them. It should be noted that the three rigs charts have almost the same behavior, this demonstrate the reliability of my calculation. Now let us speak about these operations one by one.

6.1.1 Pull Out of the Hole Bottom Hole Assembly

This operation is the one that takes more time, perhaps due its particularity, once we have to take into account well control concerns, we won’t say that to reduce this operation time, it should done quickly, because by pulling clean-up bottom hole assembly too fast may induce swab affect. Swabbing is condition that arises when pipe is pulled from the well and produces a temporary bottom hole pressure reduction. In many cases the bottom hole pressure reduction may be large enough to cause the well to go underbalanced and allow formation fluid to enter the well. By strict definition, every time the well is swabbed-in, it means that a kick has been taken. While the swab, may not necessarily cause the well to flow or cause a noticeable pit gain increase. Formation fluid produced into annulus will almost certainly lower the hydrostatic pressure of the mud column. Usually, the volume of fluid swabbed-in to the well is an insignificant amount and creates no well control problems. At other time, however, immediate action will need to be taken to prevent a further reduction in hydrostatic pressure which could cause the well to flow on its own. So we need to be careful analyze this operation and try to reduce its clean-up times.

6.1.2 Run in Hole Bottom Hole Assembly

In same way, we are lead up to well control concerns as well as in previous paragraph. We won’t say also that this operation has to be done quickly. Once by doing so, we may induce a surge effect to the well. Loss of circulation can result from rapidly lowering the clean-up bottom hole assembly. This called surging and is similar to swabbing, but in reverse; the piston action forces the drilling fluids into the weakest formations. Particular care is required when running pipe into a hole in which formation pressure and fracture pressure are relatively close.

6.1.3 Displace to Filter Brine and Displace clean-up train with seawater

Let me say that, this operation is the key point of a wellbore clean-up process, because the clean-up efficiency, depend mainly from this step. It should be noted that the two previous operations (POOH and RIH clean-up BHA) are directly linked to displacement operation, that is, if we are able to reduce this operation’s time, that means also, we are going to reduce clean-up bottom hole assembly’s tripping time. Then how I said in the third chapter, the necessity and importance of pre-job planning can not be over-emphasized because poor planning or design based on incomplete information may result in poor displacement, and consequently low wellbore clean-up efficiency that induce to completion tools failure and production zone’s formation damage which result in poor well productivity.

6.1.4 SASBU Wellbore Clean-Up Procedures

Once the well is drilled to TD, the drill pipe is run back to bottom with a bit (no jest) and properly spaced-out brushes/scrapers. The mud is circulated and conditioned and the displacement takes place in three (3) stages, as shown below. The displacement outline is graphically depicted in Figure 9.

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Wellbore Clean-up

1. indirect Displacement of Casing/Liner

a. Pick up drill pipe and run into casing to the top of the ECP and circulate 25 bbl of Transition Spacer to set on top of the residual FazePro. This will leave approximately 400’ of transition spacer in the casing. Pull the end of the drill pipe approximately 300’ (3 stands) and check for losses.

25 bbl Transition Spacer Composition

i. 0.94 bbl 9.7 ppg KClii. 1.25 gal/bbl Safe Vis E (liquid HEC) or 4 ppb dry HECiii. 5 vol% Safe Solv OMiv. 1 vol% Surfactant

b. After confirming that the wellbore is static, pump the remainder of the displacement spacers, followed by KCl brine, taking returns up the choke and kill lines.

Casing/Liner Wash Spacer Composition

i. 25 bbl wash spacer “A”

1. 9.4 ppg KCl2. 1 ppb citric acid

ii. 75 bbl wash spacer “B”1. Drill water2. 10 vol% Safe Surf O3. 5 vol% Safe Solv OM

Viscous Pill Composition

iii. 25 bbl Viscous Pill1. 9.4 ppg KCl2. 2 ppb XC

iv. Follow with KCl

2. Indirect Displacement of Riser

a. Position Rams to displace down the choke and kill lines while taking returns up the riser annulus

b. Pump the following Spacers and wash Chemicals at highest rate possible

100 bbl Riser Transition Spacer Composition

i. 0.94 bbl 9.7 KClii. 1.25 gal/bbl Safe Vis E (liquid HEC) or 4 ppb dry HEC

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Wellbore Clean-up

iii. 10 vol% Safe Solv OMiv. 5 v0l % Safe Surf O

Riser Wash Spacer composition

v. 25 bbl Wash Spacer “A”1. Seawater2. 1 ppb Citric Acid

vi. 100 bbl Wash Spacer “B”1. Seawater2. 10 vol% Safe Surf O3. 5 vol% Safe Solv OM

Viscous Pill Composition

vii. 25 bbl Viscous Pill

Seawater

viii. Seawater (open boost valve and pump through boost).

c. Pump Seawater until an NTU of 75 is attainedd. Displace Seawater to 9.4 KCl. Pump down choke, kill and boost lines while taking

returns up annulus.

i. 25 bbl Viscous Pill (Seawater + 2 ppb XC)ii. 9.4 ppg KCl

Clean Stack and Short Trip

1. Drop activating ball and open jetting tool2. Jet stack at 8 to 12 bpm in brine3. Open boost line an d pump at 24 to 30 bpm in riser annulus while jetting4. Drop ball to deactivate jetting tool5. Short trip to the lowest riser brush

Filter Brine

1. Go back to the top of the transition spacer.2. Circulate and filter the fluid in the casing, taking returns up choke and boost lines.3. POOH with drill pipe after 50 NTU reading is attained.4. Circulate and filter fluid in the riser to spec while POOH.

3. Displacement of residual fazepro from open hole

a. RIH with drill pipe to top of ECP. Pump “Open-hole Push Pill” to bottom of drill pipe.

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Wellbore Clean-up

b. Slowly run to TD taking care not to surge the wellbore. Fill pipe while RIH with Open-hole push pill (enough to fill screen/CAPS annulus). Allow 2 to 5 bbl excess as a buffer.

c. Once on bottom, begin pumping and follow push pill with enough KCl to fully displace the residual FazePro from the OH.

yd. Pump the following spacers:

125 bbl Open Hole Push Pill Composition

i. 0.63 bbl 9.7 ppg KClii. 0.34 bbl 11.3 CaCl2

iii. 1.5 gal/bbl Safe Vis E (liquid HEC) or 4 ppb dry HECiv. 0.1 ppb KOH (buffer to 9.0)v. 0.5 vol% Safe-Break CBF (Non-emulsifier)

Casing Wash Spacers Composition

vi. 25 bbl Wash Spacer “A”1. 9.4 ppg KCL2. 1 bbp Citric Acid

vii. 50 bbl Wash Spacer “B”1. Drill water2. 10 vol% Safe Surf O3. 5 vol% Safe Solv OM

Viscous Pill Composition

viii. 25 bbl Vicous Pill1. 9.4 ppg KCl 2. 2 ppb XC

Follow with KCl with treated with 0.5 vol% Safe Break CBF

6.2 SASBU Wellbore Clean-up Operations Average Times

Now let me determine SASBU’s average time for each wellbore clean-up operation; as we said before the results are shown in chart form, to give you better understanding. The chart below shows the average time and as well as the percent that ServComp1 are doing for each operation.

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Wellbore Clean-up

Figure 6.3 SASBU’s average wellbore clean-up times

6.3 Ser.1’s Clean-up Times versus Ser.2, Ser.3 and Ser.4 Clean-up Times In this item I am going to compare Ser.1 clean-up operations’ times with those of the Ser.2, Ser.3 and Ser.4. Here I want say that, the Ser.2, Ser.3 and Ser.4 wellbore clean-up’s data were given to me by TOTAL, Ser.3 and Ser.4 drilling department’s representative. I will do this comparison by using charts (see Figure 6.4).

I said in item 6.1.3 that, displacement is the key point of a wellbore clean-up process. Based on this fact, I will show only the operations related to displacement, such as displacement kill, choke and booster lines, Circulate pills & seawater and displace filtered brine. Even thought, we should pay maximum attention to others operations, mainly those ones related to wellbore drill string and bottom hole assembly tripping; once they are of great importance for well control concerns.

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SASBU Average Clean-up Time

M/U & RIH Cleanup BHA11.427%

Diplacement Kill,Choke and Booster Lines

25%

Circulate Pills and seawater to 50-20 NTU +/-

4.510%

POOH & LD Cleanup BHA

1023%

Displace to Filtered Brine6.2

14%

Debris removal with Junk basket or Magnet

3.58%

Displace Cleanup Train w/ Seawater

5.413%

Wellbore Clean-up

Figure 6.4 Blocks 14, 15, 17 and 18 Services Companies’ Clean-up Times

In the chart above we see that, the three companies are taking different times for the same operations, perhaps somebody may say, this natural once they are working in difference places, but we want to remind you that, all these places are deep water blocks. In block 14 the average water depth is 1200m;in block 15 is 1300m; in block 17 is 1300m and in block 18 is 1250m. We see clearly that Ser.2 is doing less time for these three operations, look to the time percentage on the chart below. Why is Ser.2 performing less time? You can find the answer by looking to the following three key points:

1. Spacer and pills chemical – It is Ser.2 philosophy using very powerful clean-up chemical products that are friendly to environment in order to achieve an efficient wellbore clean-up in short time (Using powerful chemical product we reduce contact time).

2. Displacement direction – Ser.2 is using forward direction to remove the displacement fluids (mud, spacer and brine) from the wellbore, as we already described on chapter 3, in forward displacement fluids are pumped down the workstring and up the casing annulus and the pressure is applied to the workstring, so in term of well control concerns we can RIH and POOH the clean-up assembly faster than in reverse circulation.

3. Displacement type – Ser.2 is using direct displacement type to remove the spacer/pill train from the wellbore. We know that in indirect displacement priori to displace to filter brine we circulate with seawater to displace the spacer/pill train and to clean the wellbore, to do that we need an additional rig time; this rig time is saved by using direct displacement. Ser.1 and Ser.3 are taking more time because they are using indirect displacement.

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Services Companies' Wellbore Clean-up Times

0

2

4

6

8

10

12

14

16

Ser.1 Chevron

Ser.2 TOTAL

Ser.3 EXXON

MOBILE

Ser.4 BP

Clean-up Operations

Tim

e(h

ou

rs)

Displacement Kill,Choke andbooster Lines

Circulate Pills "and seawater "to50 NTU +/-

Displaced Filtered Brine

Total

Wellbore Clean-up

Figure 6.5 Blocks 14, 15,17 and 18 Service companies’ wellbore clean-up times’ percentage

In addition Ser.2 is using Displex software for displacement design; this modeling software is used to model the displacement of drilling fluids with clean-up pills and clear brine. To aid planning the package allows users to model the flow dynamics of fluid displacement in 3-D wells, as well as ECD’s and pressures. Displex also enables users to simulate fluid displacement and flow patterns, and calculate the flow rate required to produce turbulent flow (required for maximum hole cleaning) at different borehole geometries.

We think that Ser.1 are also doing a good job, they have good chemical products and clean-up tools; for instance they have a powerful downhole filter debris which is called well patroller. The Well Patroller Downhole Filter Tool is an advanced wellbore cleanup tool developed for use in the pre-drillstem test (DST)/completion phase of wells, where a high degree of cleanliness is required. ServComp1 is using Single Action Bypass Sub Jetting Tool, which is run in the hole in the open position to jet and clean through the riser and wellhead/BOP area.

6.4 Wellbore Clean-up Efficiency

The wellbore clean-up efficiency or performance is evaluated by looking on degree of cleanliness. The degree of cleanliness degree is measured in NTU (nephelometric turbidity units), this means that how greater is NTU less clarity or degree of cleanliness we have so I would like to invite you to see NTU values that Ser.1, Ser.2, Ser.3 and Ser.4 are performing:

e. Ser.1 20 – 50 NTU +/-

f. Ser. 40 – 70 NTU +/-

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Ser.1 Clean-up Time Versus Ser.2, Ser.3 and Ser.4 Times

Ser.3 EXXON MOBILE

13.5331%

Ser.2 TOTAL

5.513%

Ser.4 BP12

27%

Ser.1 Chevron

12.729%

Wellbore Clean-up

g. Ser.3 50 – 100 NTU +/-

h. Ser.4 50 – 100 NTU +/- The service company ser.1 is the one that achieve the NTU specification of 50 in less time, the second one is ser.2 then the ser.4 and lastly the ser.3. Then we conclude that the Ser.1 has the best wellbore clean-up performance.

6.5 Economical Evaluation

I want start this economical evaluation with Ser.1 which is the service company working for Chevron. I am going to describe the well completion cost estimation for +/- 12000’MD.

1. Displacement Tools

A. Well Design

1. 2 - Riser Brush1 – 10 ¾” SPS Bristle Back 1 – 10 ¾” Speedwell Magnet1 – 10 ¾” SPS Razor Back 1 - 9 5/8” SPS Bristle Back1 – 9 5/8” Speedwell Magnet 1 – 9 5/8” SPS Razor Back 1 – 9 5/8” Speedwell Brush1 – 9 5/8” Speedwell Magnet1 – 9 5/8” Speedwell Scraper

B. Tool Cost

$78,820.00

2. Displacement Chemicals

A. Conditioning Spacers

1. Spacer 1- 2 barrels - 3 ppb equivalent Xanvis L @ 9.3 ppg2. Wash Pill 1 - 2 barrels – Neat SafeSolve OM3. Spacer 2 - 3 barrels - 3 ppb equivalent Xanvis L @ 9.3 ppg4. Wash Pill 2 - 30 barrells - 20% SafeSurf O mixed with FSW5. Spacer 3 - 2 barrels - 3 ppb equivalent Xanvis L @ 9.3 ppg

B. Displacement Spacers

1. Wash Pill 1 - 40 barrels - SafeSolve OM2. Spacer 2 - 50 barrels - 3 ppb equivalent Xanvis L @ 9.3 ppg3. Wash Pill 2 - 170 barrels -20% SafeSurf O mixed with FSW4. Spacer 3 -100 barrels -3 ppb equivalent Xanvis L @ 9.3 ppg5. Spacer 4 - 100 barrels - 9.7 ppg KCL – Non viscosified6. Wash Pill 3 - 100 barrels - Sea Water + SafeFloc II (1 drum / 100 barrels)

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Wellbore Clean-up

C. Displacement Chemical Cost

$23,432.00

3. Rig Time Cost

According with the chart on figures 6.2-a and 6.2-b we see that the average time for the all clean-up operations is 43hrs, and we know that the average rig cost per day is $458,000.00, then the rig average cost per hour will be $19,083.30 and the total rig cost will be $820,583.00.

The total cost for this wellbore clean-up operation will be:

Total Cost = $78,820.00 + $23,432.00 + $820,583.00 = $922,835.00

Now see the chart below that illustrates the Ser.1, Ser.2, Ser.3 and Ser.4 total wellbore clean-up cost.

Figure 6.6 Blocks 14, 15 and 17 Service Companies Wellbore Clean-up Total Costs

We see above that in term of wellbore clean-up cost the service companies Ser.2, Ser.3 and Ser.4 have less costs than Ser.1, but don’t forget that for this analyze we have to take into account two variables, which are wellbore clean-up cost and efficiency. It should be noted that, in term of efficiency the Ser.1 has the best performance, this mean that at end of day the Ser.1 wellbore clean-up operations result in less problem concerning to completion failure and formation damage, which imply better well productivity.

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$-

$100,000.00

$200,000.00

$300,000.00

$400,000.00

$500,000.00

$600,000.00

$700,000.00

$800,000.00

$900,000.00

$1,000,000.00

Ser.1 Chevron

Ser.2 TOTAL

Ser.3 EXXON

MOBILE

Ser.4 BP

Wellbore Clean-up Total Cost

Wellbore Clean-up

Chapter 7 Conclusion and Recommendations 7.1 Conclusion

Throughout this study we saw the importance to have a good wellbore clean-up performance, in order to avoid completion and formation damage, which may induce to an additional rig time (workover) and poor well productivity.

Wellbore clean-up performance is achieved by use of powerful displacement chemicals friendly to environment with right mechanical downhole cleaning tools assistance and use of Displex software to plan displacement’s Hydraulics and mechanics; we can confirm this looking to Ser.2 and Ser.1 wellbore clean-up procedures, these companies achieved good results because they follow those guidelines.

We conclude also that SASBU rigs are doing good job in term of wellbore clean-up operations; they have almost the same wellbore clean-up procedures, which is natural because Ser.1 is the service company that is providing these services to the rigs. Let us say that Ser.1 could do much better by developing powerful spacer and pill chemicals and by use of the best displacement methods to clean the wellbore more efficiently at less time and lower cost.

We want finalize our conclusion with a question that is how to develop really a powerful chemicals products for wellbore clean-up, which are in their way friendly to environment? I think that operators and services companies should focus their attention on this.

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Wellbore Clean-up

7.2 Recommendations7.2.1Wellbore Clean-up Guidelines for SASBU I have developed the following wellbore clean-up’s guidelines that I recommend to be followed by SASBU: To Use Forward Direction Displacement – By using this circulation direction we save time, because we will be able to circulate, run in hole and pull out of the hole the workstring fast than in reverse circulation, once in forward direction pump direction is that the pump pressure is contained in the workstring rather than transmitted to the annulus, so we have less problem related with well control concerns.

Forward circulation allows rotation and reciprocation of the workstring when the blow-out preventer and pipe rams remain open. Pipe movement is important in a deviated wellbore. Forward circulation allows higher pump rates and less frictional pressure losses over the course of displacement. It also allows greater control over differential pressure across sensitive areas such as liner tops and squeezed perforations.

To use Direct Displacement – By using direct displacement we save also time, because by using this displacement method we need only one or two bottom up to clean the wellbore rather than four or more bottom up in indirect displacement. It should be noticed that in direct displacement we only use powerful chemicals wash spacer to clean the wellbore instead of seawater circulation which takes a lot of time and produce a large amount of waste which induce to higher cost for waste management and environment concerns in indirect displacement method.

To use Single combination tools – By using single combination tools we save times, because instead of RIH and POOH one tool each time we can do these trips simultaneously with two or more tools, for instance we can combine scrappers, Brush, magnetic and Jetting tools in same workstring (see Figure 6.6).

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Bit

Jet Tool

Combination ToolScraper/Brush

Magnet Tool

Jet Tool

Figure 6.6 Single Combination Tool

Wellbore Clean-up

Now let me explain the way that the above single combination tool built by me works. As you can see it is composed of two jetting tools, one scrapper/brush combination tool and a magnet tool which as following:

• RIH the single combination tool with first jetting tool in close position

• Scrape and brush the casing or tubular surface with scrapper/brush while circulating

• Remove the ferrous metal debris with magnet tool.

• Flush the tubular surface with second jetting tool.

• POOH the single combination tools with the first and second jetting tools in open position to flush the tubular surface.

This single combination clean-up tool could be study thoroughly in future for next wellbore clean-up challenge.

To Develop more Powerful chemicals pills spacer that are Friendly to Environment – By developing this kind of chemicals products we can clean the wellbore only with small volume of spacer or pills and we will need less contact time in order to achieve a good wellbore clean-up performance. I want recommend also that these chemicals products should produce exothermic reaction with some debris in order to produce heat energy which will be used to increase the wellbore clean-up efficiency at short time.

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Section

Wellbore Clean-up

Recommended wellbore clean-up Procedures

According with the guidelines described above I recommend the following wellbore clean-up procedures:

Surface Equipment preparation

• Clean the pit system priori to displacing the hole to brine

• Test Bop according to its working pressure (While cleaning mud pits)

• Thoroughly clean all rig circulating system with a pressure cleaner and flocculent flush. Circulate through lines at maximum possible rate.

Wellbore clean-up operations

• M/U and RIH the clean-up BHA to TD

• P/U the bit to 100' above casing shoe

• Circulate viscous or transition spacer

• Circulate wash pills until reach 150 NTU

• Circulate and filter brine until the specification of 20 NTU is met.

• Displace well with filter brine

• POOH and L/D clean-up BHA

I want finally give the following recommendations to SASBU’s rigs:

• To use forward direction for almost displacements operations with exception for riser displacement.

• To use direct displacement to displace cased and open hole.

• To work together with other companies in order to develop powerful spacer/pill chemicals for wellbore clean-up friendly to environment.

• To compare Ser.p1 clean-up procedures with other services companies.

• To develop single combination tools.

• To require wellbore clean-up services from ServComp2

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Wellbore Clean-up

Bibliography

Books Research

• Drilling Fluid Manual• Applied Drilling Engineering (By Adam Boutgoyner, Martn E. Chenevert, Keith K.

Millheim and F.S. Young Jr.)

Chevron Network Research

• SASBU’s Sites• Diswin

Internet research

http://www.spsinternational.com/uploads/Animations/Scottishwell_patroller-web2.swf

http://www.spsinternational.com/uploads/Animations/Scottishwell_MFCT®-web2.swf

http://www.spsinternational.com-uploads-images-Tools131.jpg

http://www.wellborespecialties.com/

http://solutionsguide.tetratec.com/index.asp?Page_ID=734&AQ_Magazine_Date=Current&AQ_Magazine_ID=2243

http://www.thru-u.com/products.php

http://www.tetratec.com/Products_and_Services/Fluids_and_Filtration/Cleanup_and_Displacement/TDSP_II.aqf

http://www.tetratec.com/Index.asp?page_ID=324&skip_frames=&site_ID=3

http://www.mms.gov/glossary/si-sp.htm#sonic%20logging

http://www.answers.com/casing

http://www.emagister.com/manual-mineralogia-petrologia-cursos-638478.htm

http://www.dyna-coil.com/website/Completions.nsf/sl/WellboreCleaningServices?opendocument

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Wellbore Clean-up

http://www.deep-south-chemical.com/spec-tools.htm

http://www.spsinternational.com/uploads/Animations/SABSDABSJetting_Tool-web.swf

http://www.spsinternational.com/uploads/Animations/WBJT_Tool-web.swf

http://www.well-flow.com/casing-centralizers.html

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