Rep
Repú
ública de Angola
blica de Angola
Universidade Agostinho Neto
Universidade Agostinho Neto
Institut Fran
Institut Français
çais du P
du Péétrole
trole
Wellbore Clean up a Case Study
Wellbore Clean up a Case Study
By By
Nsingi Mvuka Antonio Nsingi Mvuka Antonio A thesis submitted to Institut Fran
A thesis submitted to Institut Françaisçais du Petroledu Petrole Major in Petroleum Engineering
Major in Petroleum Engineering
Supervisor Supervisor Adrian Eunson
Adrian Eunson (SA(SASBU Chevron Drilling Engineer Manager)SBU Chevron Drilling Engineer Manager)
SASBU Drilling Engineer Mentor SASBU Drilling Engineer Mentor
Bill Steven Bill Steven
Luanda
Luanda –– AngolaAngola February 2008 February 2008
Dedication
Dedication
This project is dedicated to my family which has been with me all this time, encouraging and This project is dedicated to my family which has been with me all this time, encouraging and supporting me during my course.
Dedication
Dedication
This project is dedicated to my family which has been with me all this time, encouraging and This project is dedicated to my family which has been with me all this time, encouraging and supporting me during my course.
a c k
a c k n o w le d m
n o w le d m e n ts
e n ts
First
First of all I want thank God the source of my life and of the all knowledge, for all that he hasof all I want thank God the source of my life and of the all knowledge, for all that he has been to me, I want thank also all my teachers, colleagues, the Agostinho Neto University and PEP been to me, I want thank also all my teachers, colleagues, the Agostinho Neto University and PEP managers and staff
Contents
Page
Chapter 1 Introduction
………. 11.1 Problem Statement ……….... 1
1.2 Objectives ……….. 2
Chapter 2 General Considerations
………. 32.1 What is Wellbore clean-up? ……….. 3
2.2 Why do We Clean-up the Wellbore? .………... 3
2.3 How and Where We do Clean-up ………. 3
2.4 Completion Type and Wellbore Clean-up………. 3
2.4.1 Formation Damage ……… 4
2.4.1.1 Types of Formation Damage From Fluids Used in Completion……… 4
2.4.1.2 Sensitivity Studies……….. 5
2.4.2 Completion Damage ………... 7
Chapter 3 Wellbore Displacement
……….... 93.1 Displacement Objectives ………... 9 3.2 Displacement Considerations ……… 9 3.2.1 Pre-Job Planning ………... 10 3.2.2 Pumping Direction ……… 10 3.3 Displacement Types ……….. 12 3.3.1 Direct Displacement ……….. 13 3.3.2 Indirect Displacement ………... 13 3.3.3 Staged Displacement ………. 15 3.4 Operational Considerations ………... 15
3.4.1 Surface Pit and Clean-up Equipment ……… 15
3.4.1.1 Invert Emulsion Systems ………... 15
3.4.1.2 Water Based System ……….. 15
3.4.2 Conditioning the mud .……….. 16
3.4.3 Pump Rate ………. 16
3.4.4 Hydraulic and Pump Pressure ………... 17
3.4.5 Mechanical Assistance …..……… 17
3.4.6 Spacers……… 18
3.4.6.1 Laboratory Spacer Formulation and Compatibility ……….. 22
3.4.6.2 Base Fluid Spacer ……….. 22
3.4.6.3 Transition Spacer ………... 22
3.4.6.4 Wash Spacer ……….. 24
4.5 Filtration System Guidelines ………. 33
4.5.1 Maximum Flow Rate ………. 34
Page
4.5.2 Sources of Solids in Clean Fluids ………. 344.5.3 Weight and Volume of Solids in Dirty Completion Fluid ……… 34
4.6 Types of Filtration ………. 35
4.6.1 Multi-media High Rate Filters ……….. 36
4.6.2 Tubular Filter ………. 36
4.6.3 Plate and Frame (Press) Filter ………... 37
4.7 Filtration Process ………... 39
4.8 Clarity ……… 40
4.8.1 Brine Sample Evaluation ………... 41
4.8.2 Equipment and Materials for Field Testing ………... 41
4.8.3 Sampling Methods and Sampling Points ……….. 42
4.8.4 Laboratory Gravimetric Test ………. 43
4.8.4.1 Equipment and Materials ……….. 43
4.9 Turbidity ……… 44
Chapter 5 Mechanical Assistance
……….. 465.1 Wellbore Clean-up Tools ……….. 46
5.1.1 Casing Scraper ………... 46
5.1.2 Casing Brush ………. 47
5.1.3 Riser Brush ……… 48
5.1.4 Scraper/Brush Tool ………... 49
5.1.5 Jetting Tool ……… 50
5.1.6 Downhole Debris Filter ………. 51
5.1.7 Magnet Assembly ……….. 52
Chapter 6 Results an d Discussions
………... 536.1 Ser.1Wellbore Clean-up Operations in Block 14 ………... 53
6.1.1 Pull Out of the Hole Bottom Hole Assembly ……… 56
6.1.2 Run In Hole Bottom Hole Assembly ……… 56
6.1.3 Displace to Filter Brine and Displace Clean-up Train with Seawater……... 56
6.1.4 SASBU Clean-up Procedures ……… 56
6.2 SASBU Wellbore Clean-up Operations Average Times ……….. 59
6.3 Ser.1 Clean-up Time Versus Ser.2, Ser.3 and Ser.4 wellbore Clean-up Times ……….. 60
6.4 Wellbore Clean-up Efficiency ………... 62
6.5 Economical Evaluation ………. 63
Chapter 7 Conclusion and Recommendations
………... 657.1 Conclusion ………. 65
7.2 Recommendations ……….. 66
7.2.1 Wellbore Clean-up Guidelines for SASBU ……… 66
Bibliography……….. 69
List Of Figure
3.1.a Comparison of Pump Pressure Required for Forward/Reverse Circulation. 12 3.1.b Friction Pressure and Annular Velocity vs Pumping Rate ……… 123.2 Schematic of Direct Displacement ……… 13
3.3 Schematic of Indirect Displacement ………. 14
3.4 Scraper/Brush Combination ……….. 17
3.5 Compatible Spacer Prevents the Formation of Viscosity Hump …………... 18
3.6 Example of Various Spacers Utilized in the Displacement of Water Based Mud ………... 19
3.7 Flow Regime During Displacement ……….. 20
3.8 Example of Various Spacers Utilized for The Displacement of Oil/Synthetic Based Mud ……….. 21
3.9 Transition Spacer ………... 23
3.10 Cleaning Efficiency versus Contact Time ………. 25
3.11 Cleaning Efficiency of Surfactant Wash Space ……… 26
4.1 Cartridge Filters ………. 35
4.2 Downhole Sand Filter ……… 36
4.3 Multi-media High Rate Filter ……… 36
4.4 Tubular Filter ………. 37
4.5 Plate and (Press) Filter ……….. 38
5.1 Casing Scrapers ………. 47 5.2 Casing Brusher ……….. 47 5.3 Riser Brush ……… 48 5.4 Scraper/Brush ……… 49 5.5 Jetting Tool ……… 50 5.6 Junk Basket ………... 51 5.7 Magnet Tool ……….. 52
6.1 Congo Basin Blocks ……….. 53
6.2.a Some SASBU’s Wellbore Clean-up Times ……….. 55
6.2.b BBLT, 701, Pride Venezuela Rigs Wellbore Clean-up Total Times ……… 55
6.3 SABU’s Average Wellbore Clean-up Times ……… 60
6.4 Services Companies’ Wellbore Clean-up Times ………. 61
6.5 Blocks 14, 15, 17 and 18 Services Companies Wellbore Clean-up percentage Times ……….. 62
6.6 Blocks 14, 15, 17 and 18 Services Companies’ Wellbore Clean-up Total Costs ……….. 64
6.7 Single Combination Tool ……….. 66
List of Tables
Table 1 Conditioning the Mud ………... 16Chapter 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.
1.2Objectives
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.
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 pre-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
Drilling Wellbore
Assurance
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 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.
2.4CompletionType and WellboreClean-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.
A formation damage mechanism can be defined as any mechanism or process that results in a reduction in permeability of a producing zone.
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.
2.4.1.1Types 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:
Pore throat lining and bridging material (XRD, SEM/EDX) Thin section - petrographic microscope analysis
Reservoir fluid analysis Porosity and permeability Pore throat sizeand 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.
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.
2.4.2.1 Debris Categorization Description
Debris 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
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.
3.1Displacement 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
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.
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.
Comparison of Pump Pressure Required for Forward / 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 Velocity vs Pumping Rate
Figure 3.1bthi s 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 direct ion. In some cases this could result in formation breakdown and high fluid losses.
3.3Displacement 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.
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 mud
Figure3.2Schematicof 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.
Figure 3.3Schematic 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.
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.
(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 1below:
Table 1 – Conditioning the mud
Property Straight or
Moderately Deviated
Deviated more than 60°
PV 15 or lees Greater than 15
YP Less than 10 Around 25
Gels 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.
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 th e 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.
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. Weighted spacers, 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 3.6 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.
Water Based Mud Spacer WBM Viscosified / weighted Spacer(+/ -500’ Annulus) Water Spacer with Caustic (+/ -750’ Annulus)
and/or
Chemical Wash Spacer (1000-1500’) Viscosified Brine
Spacer (500’) Completion fluid
Figure3.7Flow regime during displacement . Completion fluid Viscous Spacer (HEC) (500’ Concentrated Surfactants SAFE-SURF O (1500’) Hydrocarbon Solvent or base oil
(+/ -500’)
(Forward Circulation)
3- 7 Oil Mud Direct Displacement–O/SBM
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 2Spacer Design TypicalSpacerSystem
WBM O/SBM Function
Water Base oil Thin/condition mud
Viscous pill1 Viscous pill1 + OBM
surfactant
Separate/transition Water + WBM surfactant Water + OBM surfactant clean
Viscous pill2 Viscous pill2 Separate/transition
Completion fluid Completion fluid Complete well
1Weightedclose to density of mud. Viscosity greater than mud 2Prepared 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
Direct Displacement–O/SBM
Brine
Viscous Spacer (HEC) (250-500’) Concentrated Surfactants SAFE-SURF O (1000-1500’)
Weighted or Viscous Spacer
Plus SAFE-SURF O (+500’) Oil Mud
Based Oil Solvent (+/ -500’)
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.
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).
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 v iscous 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.
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.
Cleaning Efficiency (%) vs. Contact Time (minutes)
Figure 3.11Cleaning ef ficiency 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.
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 and the 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.
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%.
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:
Table3 Degree of Filtration Formation Sand Size
(Tyler mesh) Filtration Level (Microns) 20 11.84 40 5.41 80 2.49 100 2.09
4.3Relationship 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 f inished.
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
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 pa cked. 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, or2) 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 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.
